UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
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ý | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 20172018
or
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¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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Commission File Number | | Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number | | IRS Employer Identification Number |
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1-16169 | | EXELON CORPORATION | | 23-2990190 |
| | (a Pennsylvania corporation) 10 South Dearborn Street P.O. Box 805379 Chicago, Illinois 60680-5379 (800) 483-3220 | | |
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333-85496 | | EXELON GENERATION COMPANY, LLC | | 23-3064219 |
| | (a Pennsylvania limited liability company) 300 Exelon Way Kennett Square, Pennsylvania 19348-2473 (610) 765-5959 | | |
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1-1839 | | COMMONWEALTH EDISON COMPANY | | 36-0938600 |
| | (an Illinois corporation) 440 South LaSalle Street Chicago, Illinois 60605-1028 (312) 394-4321 | | |
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000-16844 | | PECO ENERGY COMPANY | | 23-0970240 |
| | (a Pennsylvania corporation) P.O. Box 8699 2301 Market Street Philadelphia, Pennsylvania 19101-8699 (215) 841-4000 | | |
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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 | | |
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001-31403 | | PEPCO HOLDINGS LLC | | 52-2297449 |
| | (a Delaware limited liability company) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000 | | |
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001-01072 | | POTOMAC ELECTRIC POWER COMPANY | | 53-0127880 |
| | (a District of Columbia and Virginia corporation) 701 Ninth Street, N.W. Washington, District of Columbia 20068 (202) 872-2000 | | |
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001-01405 | | DELMARVA POWER & LIGHT COMPANY | | 51-0084283 |
| | (a Delaware and Virginia corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000 | | |
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001-03559 | | ATLANTIC CITY ELECTRIC COMPANY | | 21-0398280 |
| | (a New Jersey corporation) 500 North Wakefield Drive Newark, Delaware 19702 (202) 872-2000 | | |
Securities registered pursuant to Section 12(b) of the Act: |
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Title of Each Class | | Name of Each Exchange on Which Registered |
EXELON CORPORATION: | | |
Common Stock, without par value | | New York and Chicago |
Series A Junior Subordinated Debentures | | New York |
Corporate Units | | New York |
PECO ENERGY COMPANY: | | |
Trust Receipts of PECO Energy Capital Trust III, each representing a 7.38% Cumulative Preferred Security, Series D, $25 stated value, issued by PECO Energy Capital, L.P. and unconditionally guaranteed by PECO Energy Company | | New York |
Securities registered pursuant to Section 12(g) of the Act: |
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Title of Each Class |
COMMONWEALTH EDISON COMPANY: |
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants |
POTOMAC ELECTRIC POWER COMPANY: |
Common Stock, $.01$0.01 par value |
DELMARVA POWER & LIGHT COMPANY: |
Common Stock, $2.25 par value |
ATLANTIC CITY ELECTRIC COMPANY: |
Common Stock, $3.00 par value |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. |
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Exelon Corporation | Yes x | | No o |
Exelon Generation Company, LLC | Yes x | | No o |
Commonwealth Edison Company | Yes x | | No o |
PECO Energy Company | Yes x | | No o |
Baltimore Gas and Electric Company | Yes x | | No o |
Pepco Holdings LLC | Yes x | | No o |
Potomac Electric Power Company | Yes o | | No x |
Delmarva Power & Light Company | Yes o | | No x |
Atlantic City Electric Company | Yes o | | No x |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. |
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Exelon Corporation | Yes o | | No x |
Exelon Generation Company, LLC | Yes o | | No x |
Commonwealth Edison Company | Yes o | | No x |
PECO Energy Company | Yes o | | No x |
Baltimore Gas and Electric Company | Yes o | | No x |
Pepco Holdings LLC | Yes o | | No x |
Potomac Electric Power Company | Yes o | | No x |
Delmarva Power & Light Company | Yes o | | No x |
Atlantic City Electric Company | Yes o | | No x |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
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| Large Accelerated Filer | | Accelerated Filer | | Non-accelerated Filer | | Smaller Reporting Company | | Emerging Growth Company |
Exelon Corporation | x | | | | | | | | |
Exelon Generation Company, LLC | | | | | x | | | | |
Commonwealth Edison Company | | | | | x | | | | |
PECO Energy Company | | | | | x | | | | |
Baltimore Gas and Electric Company | | | | | x | | | | |
Pepco Holdings LLC | | | | | x | | | | |
Potomac Electric Power Company | | | | | x | | | | |
Delmarva Power & Light Company | | | | | x | | | | |
Atlantic City Electric Company | | | | | x | | | | |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No x
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 20172018 was as follows: |
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Exelon Corporation Common Stock, without par value | | $34,604,071,95941,118,095,431 |
Exelon Generation Company, LLC | | Not applicable |
Commonwealth Edison Company Common Stock, $12.50 par value | | No established market |
PECO Energy Company Common Stock, without par value | | None |
Baltimore Gas and Electric Company, without par value | | None |
Pepco Holdings LLC | | Not applicable |
Potomac Electric Power Company | | None |
Delmarva Power & Light Company | | None |
Atlantic City Electric Company | | None |
The number of shares outstanding of each registrant’s common stock as of January 31, 20182019 was as follows: |
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Exelon Corporation Common Stock, without par value | | 965,029,399969,745,933 |
Exelon Generation Company, LLC | | Not applicable |
Commonwealth Edison Company Common Stock, $12.50 par value | | 127,021,256127,021,331 |
PECO Energy Company Common Stock, without par value | | 170,478,507 |
Baltimore Gas and Electric Company Common Stock, without par value | | 1,000 |
Pepco Holdings LLC | | Not applicable |
Potomac Electric Power Company Common Stock, $0.01 par value | | 100 |
Delmarva Power & Light Company Common Stock, $2.25 par value | | 1,000 |
Atlantic City Electric Company Common Stock, $3.00 par value | | 8,546,017 |
Documents Incorporated by Reference
Portions of the Exelon Proxy Statement for the 20182019 Annual Meeting of
Shareholders and the Commonwealth Edison Company 20182019 Information Statement are
incorporated by reference in Part III.
Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the reduced disclosure format.
TABLE OF CONTENTS
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GLOSSARY OF TERMS AND ABBREVIATIONS | |
FILING FORMAT | |
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION | |
WHERE TO FIND MORE INFORMATION | |
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PART I | | |
ITEM 1. | BUSINESS | |
| General | |
| Exelon Generation Company, LLC | |
| Utility Operations | |
| Employees | |
| Environmental Regulation | |
| Executive Officers of the Registrants | |
ITEM 1A. | RISK FACTORS | |
ITEM 1B. | UNRESOLVED STAFF COMMENTS | |
ITEM 2. | PROPERTIES | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
ITEM 3. | LEGAL PROCEEDINGS | |
ITEM 4. | MINE SAFETY DISCLOSURES | |
PART II | | |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES | |
ITEM 6. | SELECTED FINANCIAL DATA | |
| Exelon Corporation | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Pepco Holdings LLC | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | |
| Exelon Corporation | |
| Executive Overview | |
| Financial Results of Operations | |
| Significant 20172018 Transactions and Recent Developments | |
| Exelon's Strategy and Outlook for 20182019 and Beyond | |
| Liquidity Considerations | |
| Other Key Business Drivers and Management Strategies | |
| Critical Accounting Policies and Estimates | |
| Results of Operations | |
| 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 | |
| Liquidity and Capital Resources | |
| Contractual Obligations and Off-Balance Sheet Arrangements | |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | |
| Exelon Corporation | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Pepco Holdings LLC | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
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ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | |
| Exelon Corporation | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Pepco Holdings LLC | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
| Combined Notes to Consolidated Financial Statements | |
| 1. Significant Accounting Policies | |
| 2. Variable Interest Entities | |
| 3. Regulatory MattersRevenue from Contracts with Customers | |
| 4. Regulatory Matters | |
| 5. Mergers, Acquisitions and Dispositions | |
| 5. Accounts Receivable | |
| 6. Property, Plant and Equipment | |
| 7. Impairment of Long-Lived Assets and Intangibles | |
| 8. Early Nuclear Plant Retirements | |
| 9. Jointly Owned Electric Utility Plant | |
| 10. Intangible Assets | |
| 11. Fair Value of Financial Assets and Liabilities | |
| 12. Derivative Financial Instruments | |
| 13. Debt and Credit Agreements | |
| 14. Income Taxes | |
| 15. Asset Retirement Obligations | |
| 16. Retirement Benefits | |
| 17. Severance | |
| 18. MezzanineShareholders' Equity | |
| 19. Shareholders' EquityStock-Based Compensation Plans | |
| 20. Stock-Based Compensation PlansEarnings Per Share | |
| 21. Earnings Per Share | |
| 22. Changes in Accumulated Other Comprehensive Income | |
| 22. Commitments and Contingencies | |
| 23. Commitments and ContingenciesSupplemental Financial Information | |
| 24. Supplemental FinancialSegment Information | |
| 25. Segment InformationRelated Party Transactions | |
| 26. Related Party TransactionsQuarterly Data | |
| 27. Quarterly Data | |
| 28. Subsequent Events | |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | |
ITEM 9A. | CONTROLS AND PROCEDURES | |
ITEM 9B. | OTHER INFORMATION | |
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PART III | | |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE | |
ITEM 11. | EXECUTIVE COMPENSATION | |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE | |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES | |
PART IV | | |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES | |
ITEM 16. | FORM 10-K SUMMARY | |
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| Exelon Corporation | |
| Exelon Generation Company, LLC | |
| Commonwealth Edison Company | |
| PECO Energy Company | |
| Baltimore Gas and Electric Company | |
| Pepco Holdings LLC | |
| Potomac Electric Power Company | |
| Delmarva Power & Light Company | |
| Atlantic City Electric Company | |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Exelon Corporation and Related Entities |
Exelon | | Exelon Corporation |
Generation | | Exelon Generation Company, LLC |
ComEd | | Commonwealth Edison Company |
PECO | | PECO Energy Company |
BGE | | Baltimore Gas and Electric Company |
Pepco Holdings or PHI | | Pepco Holdings LLC (formerly Pepco Holdings, Inc.) |
Pepco | | Potomac Electric Power Company |
DPL | | Delmarva Power & Light Company |
ACE | | Atlantic City Electric Company |
Registrants | | Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively |
Utility Registrants | | ComEd, PECO, BGE, Pepco, DPL and ACE, collectively |
Legacy PHI | | PHI, Pepco, DPL, ACE, PES and PCI collectively |
ACE Funding or ATF | | Atlantic City Electric Transition Funding LLC |
Antelope Valley | | Antelope Valley Solar Ranch One |
BondCo | | RSB BondCo LLC |
BSC | | Exelon Business Services Company, LLC |
CENG | | Constellation Energy Nuclear Group, LLC |
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. |
EEDC | | Exelon Energy Delivery Company, LLC |
EGR IV | | ExGen Renewables IV, LLC |
EGRP | | ExGen Renewables Partners, LLC |
EGTP | | ExGen Texas Power, LLC |
Entergy | | Entergy Nuclear FitzPatrick, LLC |
Exelon Corporate | | Exelon in its corporate capacity as a holding company |
Exelon Transmission Company | | Exelon Transmission Company, LLC |
Exelon Wind | | Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC |
FitzPatrick | | James A. FitzPatrick nuclear generating station |
PCI | | Potomac Capital Investment Corporation and its subsidiaries |
PEC L.P. | | PECO Energy Capital, L.P. |
PECO Trust III | | PECO Capital Trust III |
PECO Trust IV | | PECO Energy Capital Trust IV |
Pepco Energy Services or PES | | Pepco Energy Services, Inc. and its subsidiaries |
PHI Corporate | | PHI in its corporate capacity as a holding company |
PHISCO | | PHI Service Company |
RPG | | Renewable Power Generation |
SolGen | | SolGen, LLC |
TMI | | Three Mile Island nuclear facility |
UII | | Unicom Investments, Inc. |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
AEC | | Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source |
AESO | | Alberta Electric Systems Operator |
AFUDC | | Allowance for Funds Used During Construction |
AGE | | Albany Green Energy Project |
AMI | | Advanced Metering Infrastructure |
AMP | | Advanced Metering Program |
AOCI | | Accumulated Other Comprehensive Income |
ARC | | Asset Retirement Cost |
ARO | | Asset Retirement Obligation |
ARP | | Alternative Revenue Program |
ASA | | Asset Sale Agreement |
BGS | | Basic Generation Service |
CAISO | | California ISO |
CAP | | Customer Assistance Program |
CCGTs | | Combined-Cycle gas turbines |
CERCLA | | Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended |
CES | | Clean Energy Standard |
Clean Air Act | | Clean Air Act of 1963, as amended |
Clean Water Act | | Federal Water Pollution Control Amendments of 1972, as amended |
Conectiv | | Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the Predecessor periods |
Conectiv Energy | | Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010 |
ConEdison Solutions | | The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc |
CSAPR | | Cross-State Air Pollution Rule |
CTA | | Consolidated tax adjustment |
D.C. Circuit Court | | United States Court of Appeals for the District of Columbia Circuit |
DC PLUG | | District of Columbia Power Line Undergrounding Initiative |
DCPSC | | District of Columbia Public Service Commission |
Default Electricity SupplyDDOT | | The supplyDistrict Department 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 BGSTransportation |
DOE | | United States Department of Energy |
DOEE | | Department of Energy & Environment |
DOJ | | United States Department of Justice |
DPSC | | Delaware Public Service Commission |
DRP | | Direct Stock Purchase and Dividend Reinvestment Plan |
DSP | | Default Service Provider |
DSP Program | | Default Service Provider Program |
EDF | | Electricite de France SA and its subsidiaries |
EE&C | | Energy Efficiency and Conservation/Demand Response |
EIMA | | Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036) |
EmPower Maryland | | A Maryland demand-side management program for Pepco and DPL |
EPA | | United States Environmental Protection Agency |
EPSA | | Electric Power Supply Association |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
EPSA | | Electric Power Supply Association |
ERCOT | | Electric Reliability Council of Texas |
ERISA | | Employee Retirement Income Security Act of 1974, as amended |
EROA | | Expected Rate of Return on Assets |
ESPP | | Employee Stock Purchase Plan |
FASB | | Financial Accounting Standards Board |
FEJA | | Illinois Public Act 99-0906 or Future Energy Jobs Act |
FERC | | Federal Energy Regulatory Commission |
FRCC | | Florida Reliability Coordinating Council |
GAAP | | Generally Accepted Accounting Principles in the United States |
GCR | | Gas Cost Rate |
GHG | | Greenhouse Gas |
GSA | | Generation Supply Adjustment |
GWh | | Gigawatt hour |
IBEW | | International Brotherhood of Electrical Workers |
ICC | | Illinois Commerce Commission |
ICE | | Intercontinental Exchange |
IIP | | Infrastructure Investment Program |
Illinois EPA | | Illinois Environmental Protection Agency |
Illinois Settlement Legislation | | Legislation enacted in 2007 affecting electric utilities in Illinois |
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 |
LLRW | | Low-Level Radioactive Waste |
LT PlanLNG | | Long-Term renewable resources procurement planLiquefied Natural Gas |
LTIP | | Long-Term Incentive Plan |
MAPP | | Mid-Atlantic Power Pathway |
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 |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
MOPR | | Minimum Offer Price Rule |
MRV | | Market-Related Value |
MW | | Megawatt |
MWh | | Megawatt hour |
n.m. | | not meaningful |
NAAQS | | National Ambient Air Quality Standards |
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 |
NLRB | | National Labor Relations Board |
Non-Regulatory Agreements Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting |
NOSA | | Nuclear Operating Services Agreement |
NPDES | | National Pollutant Discharge Elimination System |
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 |
NYPSC | | New York Public Service Commission |
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 |
PCB | | Polychlorinated Biphenyl |
PGC | | Purchased Gas Cost Clause |
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 of non-voting, non-convertible and non-transferable Series A preferred stock, par value $0.01 per share |
PRP | | Potentially Responsible Parties |
PSEG | | Public Service Enterprise Group Incorporated |
PV | | Photovoltaic |
RCRA | | Resource Conservation and Recovery Act of 1976, as amended |
REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source |
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GLOSSARY OF TERMS AND ABBREVIATIONS |
Other Terms and Abbreviations | | |
REC | | Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source |
Regulatory Agreement Units | | Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting |
RES | | Retail Electric Suppliers |
RFP | | Request for Proposal |
Rider | | Reconcilable Surcharge Recovery Mechanism |
RGGI | | Regional Greenhouse Gas Initiative |
RMC | | Risk Management Committee |
RNF | | Revenue Net of Purchased Power and Fuel Expense |
ROE | | Return on equity |
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) |
SGIG | | Smart Grid Investment Grant from DOE |
SILO | | Sale-In, Lease-Out |
SNF | | Spent Nuclear Fuel |
SOS | | Standard Offer Service |
SPFPA | | Security, Police and Fire Professionals of America |
SPP | | Southwest Power Pool |
TCJA | | Tax Cuts and Jobs Act
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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 |
Upstream | | Natural gas and oil exploration and production activities |
VIE | | Variable Interest Entity |
WECC | | Western Electric Coordinating Council |
ZEC | | Zero Emission Credit |
ZES | | Zero Emission Standard |
FILING FORMAT
This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed herein, including those factors discussed with respect to the Registrants discussed in (a) 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 23,22, Commitments and Contingencies; and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The public may readSEC maintains an Internet site at www.sec.gov that contains reports, proxy and copy any reports orinformation statements, and other information that the Registrants file electronically 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 at 1-800-SEC-0330.SEC. These documents are also available to the public from commercial document retrieval services the website maintained by the SEC at www.sec.govand the Registrants’ website at www.exeloncorp.com. Information contained on the Registrants’ website shall not be deemed incorporated into, or to be a part of, this Report.
PART I
General
Corporate Structure and Business and Other Information
Exelon, incorporated in Pennsylvania in February 1999, is a utility services holding company engaged, through Generation, in the energy generation business, and through ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the energy delivery businesses discussed below. Exelon’s principal executive offices are located at 10 South Dearborn Street, Chicago, Illinois 60603.
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Name of Registrant | | State/Jurisdiction and | | Business | | Service | | Address of Principal |
Year of Incorporation | Territories | Executive Offices |
| | | | | | | | |
Exelon Generation Company, LLC | | Pennsylvania (2000) | | Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.
| | Six reportable segments: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions | | 300 Exelon Way, Kennett Square, Pennsylvania 19348 |
| | | | | | | | |
Commonwealth Edison Company | | Illinois (1913) | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago | | 440 South LaSalle Street, Chicago, Illinois 60605 |
| | | | Transmission and distribution of electricity to retail customers | | | | |
| | | | | | | | |
PECO Energy Company | | Pennsylvania (1929) | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) | | 2301 Market Street, Philadelphia, Pennsylvania 19103 |
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas) | | |
| | | | | | | | |
Baltimore Gas and Electric Company | | Maryland (1906) | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) | | 110 West Fayette Street, Baltimore, Maryland 21201 |
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | | | |
| | | | | | | | |
Pepco Holdings LLC | | Delaware (2016) | | Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE | | Service Territories of Pepco, DPL and ACE | | 701 Ninth Street, N.W., Washington, D.C. 20068 |
| | | | | | | | |
Potomac Electric Power Company | | District of Columbia (1896) Virginia (1949) | | Purchase and regulated retail sale of electricity | | District of Columbia and Major portions of Montgomery and Prince George’s Counties, Maryland | | 701 Ninth Street, N.W., Washington, D.C. 20068 |
| | | | Transmission and distribution of electricity to retail customers | | |
| | | | | | | | |
Delmarva Power & Light Company | | Delaware (1909) Virginia (1979) | | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) | | 500 North Wakefield Drive, Newark, Delaware 19702 |
| | | | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) | |
| | | | | | | | |
Atlantic City Electric Company | | New Jersey (1924) | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey | | 500 North Wakefield Drive, Newark, Delaware 19702 |
| | | | Transmission and distribution of electricity to retail customers | | | | |
Business Services
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of corporate governance support services including corporate strategy and development, legal, human resources, information technology, finance, real estate, security, corporate communications and supply at cost. The costs of these services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
PHI Service Company (PHISCO),PHISCO, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, finance, 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 PHISCO and the participating operating subsidiaries.
Operating Segments
See Note 25 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s operating segments.
Merger with Pepco Holdings, Inc. (Exelon)
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI).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),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. See Note 45 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI transaction.information.
Generation
Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas, including renewable energy, in competitive energy markets to both wholesale and retail customers. The retail sales include commercial, industrial and residential customers. Generation leverages its energy generation portfolio to ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also provides geographic and supply source diversity. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer-facing activities foster development and delivery of other innovative energy-related products and services for its customers.
Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates
for sales of energy, capacity and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and holding company securities.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE and SPP as RTOs and CAISO and ISO-NY as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take transmission service across several transmission systems.
ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC.
Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional and local agencies, including the NRC and Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches.
Constellation Energy Nuclear Group, LLCCENG
Generation owns a 50.01% interest in CENG, a joint venture with EDF. CENG is governed by a board of ten directors, five of which are appointed by Generation and five by EDF. CENG owns a total of five nuclear generating facilities on three sites, Calvert Cliffs, R.E. Ginna (Ginna) and Nine Mile Point. CENG’s ownership share in the total capacity of these units is 4,0264,041 MW. See ITEM 2. PROPERTIES for additional information on these sites.
Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation’s rights to other distributions. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. In order to exercise its option, EDF must give 60-days advance written notice to Generation stating that it is exercising its option. To date, EDF has not given notice to Generation that it is exercising its option.
Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording ofrecord all assets, liabilities and EDF’s noncontrolling interests in CENG at fair value on a fully consolidated basis in Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for furtheradditional information regarding the CENG consolidation.
Acquisitions
James A. FitzPatrick NuclearHandley Generating Station
On April 4, 2018, Generation acquired the Handley Generating Station in conjunction with the EGTP Chapter 11 proceedings for a total purchase price of $62 million. See EGTP in the Dispositions section below for additional information on EGTP's November 7, 2017 bankruptcy filing.
FitzPatrick
On March 31, 2017, Generation acquired the 838 MW single-unit James A. FitzPatrick nuclear generating stationplant located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price consideration of $289 million, resulting in an after-tax bargain purchase gain of $233 million in 2017.
ConEdison Solutions
On September 1, 2016, Generation acquired the competitive retail electric and natural gas business activities of 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 were excluded from the transaction.
Integrys Energy Services, Inc.
On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. The generation and solar asset businesses of Integrys were excluded from the transaction.
Dispositions
ExGen Texas Power, LLC.EGTP
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 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, Exelon and Generation classified certain EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded associated pre-tax impairment charges of $460 million. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result of the bankruptcy filing, EGTP’s assets and liabilities were deconsolidated from Exelon and Generation's consolidated financial statements. Exelon and Generation recorded a pre-tax gain upon deconsolidation of $213 millionThe Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the fourth quarterownership of 2017.EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Asset DivestituresDispositions
During 2015 and 2014, Generation sold certain generating assets with total pre-tax proceeds of $1.8 billion (after-tax proceeds of approximately $1.4 billion). Proceeds were used primarily to finance a portion of the acquisition of PHI.
See Note 45 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated Financial Statements for additional information on acquisitions and dispositions.
Generating Resources
At December 31, 2017,2018, the generating resources of Generation consisted of the following:
|
| | |
Type of Capacity | MW |
Owned generation assets(a)(b) | |
Nuclear | 20,31019,713 |
|
Fossil (primarily natural gas and oil) | 11,7239,547 |
|
Renewable(c) | 3,1353,203 |
|
Owned generation assets(e) | 35,16832,463 |
|
Long-term power purchase contracts(d) | 5,2855,184 |
|
Total generating resources | 40,45337,647 |
|
__________
| |
(a) | See “Fuel” for sources of fuels used in electric generation. |
| |
(b) | Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information. |
| |
(c) | Includes wind, hydroelectric, solar and solarbiomass generating assets. |
| |
(d) | Electric supply procured under site specific agreements. |
| |
(e) | Includes EGTP generating assets that were deconsolidated from Generation's consolidated financial statements. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
Generation has six reportable segments, the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions, representing the different geographical areas in which Generation’s generating resources are located and Generation's customer-facing activities are conducted.
Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina (approximately 33%34% of capacity).
Midwest represents operations in the western half of PJM which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee; and the United States footprint of MISO, (excludingexcluding MISO’s Southern Region), which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin and the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM; and parts of Montana, Missouri and KentuckyRegion (approximately 34%37% of capacity).
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont (approximately 6%7% of capacity).
New York represents the operations within ISO-NY which covers the state of New York in its entirety (approximately 6% of capacity).
ERCOT represents operations within Electric Reliability Council of Texas covering most of the state of Texas (approximately 16%11% of capacity).
Other Power Regions is an aggregate of regions not considered individually significantrepresents Canada, South and West (approximately 5% of capacity).
During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 25 —24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from external customers and revenues net of purchased power and fuel expense for each of Generation's reportable segments.information.
Nuclear Facilities
Generation has ownership interests in fifteenfourteen nuclear generating stations currently in service, consisting of 2524 units with an aggregate of 20,31019,713 MW of capacity. Generation wholly owns all of its
nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75% ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), which are consolidated onin Exelon’s and Generation's financial statements relative to its proportionate ownership interest in each unit, and a 50.01% membership interest in CENG, which owns Calvert Cliffs, Nine Mile Point [excluding Long Island Power Authority's 18% undivided ownership interest in Nine Mile Point Unit 2] and Ginna nuclear stations. CENG is 100% consolidated onin Exelon's and Generation’s financial statements.
Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear, LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2018, 2017 2016 and 20152016 electric supply (in GWh) generated from the nuclear generating facilities was 69%68%, 67%69% and 68%67%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the nuclear generating stations. See ITEM 7.MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussionadditional information of Generation’s electric supply sources.
Nuclear Operations
Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on Generation’s results of operations. As the largest generator of nuclear power in the United States, Generation can negotiate favorable terms for the materials and services that its business requires. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a safe operating history.
During 2018, 2017 2016 and 2015,2016, the nuclear generating facilities operated by Generation achieved capacity factors of 94.1%94.6%, 94.6%94.1% and 93.7%94.6%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG. Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable generation base for Generation’s wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations.
In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place to protect the plant, personnel and surrounding area in the unlikely event of an accident or other incident.
Regulation of Nuclear Power Generation
Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance, emergency planning, security and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations operated by Generation, except for Clinton,Peach Bottom Units 2 and 3, are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. As of February 1, 2018,January 29, 2019, the NRC categorized ClintonPeach Bottom Units 2 and 3 in the Regulatory Response Column, which is the second highest of five performance bands. The NRC may modify, suspend or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act, the regulations under such Act or the
terms of the operating licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating facilities.
Licenses
Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the NRC for all its nuclear units except Clinton. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2. On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. In 2010, Generation had previously agreed to permanently cease generation operations at Oyster Creek by the end of 2019. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of TMI. See Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of Oyster Creek.
The following table summarizes the current operating license expiration dates for Generation’s operating nuclear facilities in service:
| | Station | Unit | | In-Service Date(a) | | Current License Expiration | Unit | | In-Service Date(a) | | Current License Expiration |
Braidwood | 1 |
| | 1988 | | 2046 | 1 |
| | 1988 | | 2046 |
| 2 |
| | 1988 | | 2047 | 2 |
| | 1988 | | 2047 |
Byron | 1 |
| | 1985 | | 2044 | 1 |
| | 1985 | | 2044 |
| 2 |
| | 1987 | | 2046 | 2 |
| | 1987 | | 2046 |
Calvert Cliffs | 1 |
| | 1975 | | 2034 | 1 |
| | 1975 | | 2034 |
| 2 |
| | 1977 | | 2036 | 2 |
| | 1977 | | 2036 |
Clinton(b) | 1 |
| | 1987 | | 2026 | 1 |
| | 1987 | | 2026 |
Dresden | 2 |
| | 1970 | | 2029 | 2 |
| | 1970 | | 2029 |
| 3 |
| | 1971 | | 2031 | 3 |
| | 1971 | | 2031 |
FitzPatrick | 1 |
| | 1974 | | 2034 | 1 |
| | 1974 | | 2034 |
LaSalle | 1 |
| | 1984 | | 2042 | 1 |
| | 1984 | | 2042 |
| 2 |
| | 1984 | | 2043 | 2 |
| | 1984 | | 2043 |
Limerick | 1 |
| | 1986 | | 2044 | 1 |
| | 1986 | | 2044 |
| 2 |
| | 1990 | | 2049 | 2 |
| | 1990 | | 2049 |
Nine Mile Point | 1 |
| | 1969 | | 2029 | 1 |
| | 1969 | | 2029 |
| 2 |
| | 1988 | | 2046 | 2 |
| | 1988 | | 2046 |
Oyster Creek(c) | 1 |
| | 1969 | | 2029 | |
Peach Bottom(d) | 2 |
| | 1974 | | 2033 | |
Peach Bottom(c) | | 2 |
| | 1974 | | 2033 |
| 3 |
| | 1974 | | 2034 | 3 |
| | 1974 | | 2034 |
Quad Cities | 1 |
| | 1973 | | 2032 | 1 |
| | 1973 | | 2032 |
| 2 |
| | 1973 | | 2032 | 2 |
| | 1973 | | 2032 |
Ginna | 1 |
| | 1970 | | 2029 | 1 |
| | 1970 | | 2029 |
Salem | 1 |
| | 1977 | | 2036 | 1 |
| | 1977 | | 2036 |
| 2 |
| | 1981 | | 2040 | 2 |
| | 1981 | | 2040 |
Three Mile Island(e) | 1 |
| | 1974 | | 2034 | |
Three Mile Island(d) | | 1 |
| | 1974 | | 2034 |
__________
| |
(a) | Denotes year in which nuclear unit began commercial operations. |
| |
(b) | Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has advised the NRC that any license renewal application would not be filed until the first quarter of 2021. |
| |
(c) | On July 10, 2018, Generation had previously announced and notified the NRC that it will permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. |
| |
(d) | On June 7, 2016, Generation announced that it will submitsubmitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3 in 2018.3. |
| |
(e)(d) | On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019 and has notified the NRC. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately two years for Generation to develop the application and approximately two years for the NRC to review the application. To date, each granted license renewal has been for 20 years beyond the original operating license expiration. Depreciation provisions are based on the estimated useful lives of the
stations, which reflect the actual renewal of operating licenses for all of Generation’s operating nuclear generating stations except for Oyster Creek, TMI and Clinton. InBeginning in 2017, Oyster Creek and TMI depreciation provisions wereare based on
their its 2019 expected shutdown dates.date. Beginning February 2018, Oyster Creek depreciation provisions will be based on its announced shutdown date of 2018.in 2016, Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 34 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional detailinformation on the new Illinois legislationFEJA and Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional detailinformation on early retirements.
Nuclear Waste Storage and Disposal
There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask storage facilities to support operations.
As of December 31, 2017,2018, Generation had approximately 84,10087,100 SNF assemblies (20,600(21,400 tons) stored on site in SNF pools or dry cask storage (thiswhich includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioning Zion Station has been assumed by another party; see Note 15 — Asset Retirement Obligations ofparty, and Oyster Creek, which is no longer operational. See the Combined Notes to Consolidated Financial StatementsDecommissioning section below for additional information regarding Zion Station Decommissioning).and Oyster Creek. All currently operating Generation-owned nuclear sites have on-site dry cask storage, except for TMI, where such storage is projected to be in operation in 2021. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at Generation’s sites through the end of the license renewal periods and through decommissioning.
For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an agreement, although neither state currently has an operational site and none is anticipated to be operational until after 2020.
Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Oyster Creek and Salem) and Connecticut.
Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through 2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and Class C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an LLRW reduction program to minimize on-site storage and cost impacts.
Nuclear Insurance
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for details.additional information.
For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial conditions and results of operations and cash flows.statements.
Decommissioning
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDTs. The NDTs are recorded onin Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 20172018 at fair value of approximately $13.3$12.7 billion and have an estimated targeted annual pre-tax return of 4.8%5% to 6.4%6.2%, while the Nuclear AROs are recorded onin Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 20172018 at approximately $9.7$10.0 billion and have an estimated annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units. The NDTs and AROs include Oyster Creek balances classified as Assets held for sale and Liabilities held for sale, respectively, in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive Overview; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Note 34 — Regulatory Matters, Note 5 - Mergers, Acquisitions and Dispositions, Note 11 — Fair Value of Financial Assets and Liabilities and Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.
ZionOyster Creek Generating Station Decommissioning.. On December 11, 2007,July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of Oyster Creek located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations. See Note 5 - Mergers, Acquisitions and Dispositions and Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the sale of Oyster Creek.
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 LLC (ZionSolutions) under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is in Zion, Illinois, and ceased operation in 1998.Station.
On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement; specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements shallwill be deferred until such milestones are met. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station decommissioning and see Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for a discussion of variable interest entity considerations related to ZionSolutions.
Fossil and Renewable Facilities (including Hydroelectric)
At December 31, 2017,2018, Generation had ownership interests in 14,85812,750 MW of capacity in generating facilities currently in service, consisting of 11,7239,547 MW of natural gas and oil, and 3,1353,203 MW of renewables (wind, hydroelectric, solar and solar)biomass). Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) Wyman; (2) certain wind project entities and a biomass project entity with minority interest owners; and (3) ExGen Renewables Partners, LLCEGRP which is owned 49% by another owner. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding certain of these entities which are VIEs. Generation’s fossil and renewable generating stations are all operated by Generation, with the exception of LaPorte and Wyman, which areis operated by a third parties.party. In 2018, 2017 2016 and 2015,2016, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 12%11%, 10%12% and 8%10%, respectively, of Generation’s total electric supply. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. For additional information regarding Generation’s electric generating facilities, see ITEM 2. PROPERTIES — Exelon Generation Company, LLC and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive Overview for additional information on Generation Renewable Development.
Licenses
Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one. FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy Run). On August 29, 2012 and August 30, 2012, Generation submitted hydroelectricMuddy Run's license applications to the FERC for 46-year licenses for the Conowingo and Muddy Run, respectively. On December 22, 2015, FERC issued a new 40-year license for Muddy Run. The license term expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a 46-year license for Conowingo. Based on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration of the plant’s license on September 1, 2014. The FERC is required to issue annual licenses for Conowingo until the new long-term license is issued. OnAs a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. The annual license renews automatically absent any further FERC action. The stations are currently being depreciated over their estimated useful lives, which includes actual and anticipated license renewal periods. Refer toSee Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Insurance
Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract or financing agreements. Refer toSee Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s future financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES — Exelon Generation Company, LLC.
Long-Term Power Purchase Contracts
In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The following tables summarize Generation’s long-
termlong-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2017:2018:
| | Region | | Number of Agreements | | Expiration Dates | | Capacity (MW) | | Number of Agreements | | Expiration Dates | | Capacity (MW) |
Mid-Atlantic | | 14 |
| | 2019 - 2032 | | 237 |
| | 14 |
| | 2019 - 2032 | | 237 |
|
Midwest | | 4 |
| | 2019 - 2026 | | 834 |
| | 4 |
| | 2019 - 2026 | | 834 |
|
New England | | 7 |
| | 2018 | | 40 |
| | 7 |
| | 2019 - 2021 | | 40 |
|
ERCOT | | 5 |
| | 2020 - 2031 | | 1,524 |
| | 5 |
| | 2020 - 2031 | | 1,524 |
|
Other Power Regions | | 12 |
| | 2018 - 2030 | | 2,650 |
| | 11 |
| | 2019 - 2030 | | 2,549 |
|
Total | | 42 |
| | 5,285 |
| | 41 |
| | 5,184 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | Thereafter | | Total |
Capacity Expiring (MW) | | 141 |
| | 644 |
| | 1,020 |
| | 815 |
| | 298 |
| | 2,367 |
| | 5,285 |
|
|
| | | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | Thereafter | | Total |
Capacity Expiring (MW) | | 673 |
| | 1,020 |
| | 826 |
| | 298 |
| | 167 |
| | 2,200 |
| | 5,184 |
|
Fuel
The following table shows sources of electric supply in GWh for 20172018 and 2016:2017:
| | | Source of Electric Supply | Source of Electric Supply |
| 2017 | | 2016 | 2018 | | 2017 |
Nuclear(a) | 182,843 |
| | 176,799 |
| 185,020 |
| | 182,843 |
|
Purchases — non-trading portfolio | 51,595 |
| | 59,987 |
| 59,154 |
| | 51,595 |
|
Fossil (primarily natural gas and oil) | 22,546 |
| | 19,830 |
| 21,015 |
| | 22,546 |
|
Renewable(b) | 7,848 |
| | 6,324 |
| 8,469 |
| | 7,848 |
|
Total supply | 264,832 |
|
| 262,940 |
| 273,658 |
|
| 264,832 |
|
__________
| |
(a) | Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g., CENG). Nuclear generation for 20172018 and 20162017 includes physical volumes of 34,76135,100 GWh and 33,44434,761 GWh, respectively, for CENG. |
| |
(b) | Includes wind, hydroelectric, solar and solarbiomass generating assets. |
The fuel costs per MWh for nuclear generation are less than those for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-effective way for Generation to meet its wholesale and retail load servicing requirements.
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride and the fabrication of fuel assemblies. Generation has inventory in various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment or fabrication services to meet the nuclear fuel requirements of its nuclear units.
Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.
Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates and Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative financial instruments.
Power Marketing
Generation’s integrated business operations include physical delivery and marketing of power. Generation largely obtains physical power supply from its generating assets and power purchase agreements in multiple geographic regions. Power purchase agreements, including tolling arrangements, are commitments related to power generation of specific generation plants and/or dispatch similar to an owned asset depending on the type of underlying asset. The commodity risks associated with the output from generating assets and PPAs are managed using various commodity transactions including sales to customers. The main objective is to obtain low-cost energy supply to meet physical delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas and other energy related products and solutions to various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental and residential customers in competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs.
Price and Supply Risk Management
Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities. Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 20182019 and beyond for portions of its electricity portfolio
that are unhedged. As of December 31, 2017,2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 85%-88%89%-92%, 55%-58%56%-59% and 26%-29%32%-35% for 2018, 2019, 2020, and 2020,2021, 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, which include economic hedges and certain non-derivative contracts, including sales to ComEd, PECO, BGE, Pepco, DPL and ACE to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel products based on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitor the financial risks of the wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity accounts for only a small portion of Generation’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
Capital Expenditures
Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated capital expenditures for 20182019 are approximately $2.1$2.0 billion, which includes Generation's share of the investment in nuclear fuel for the co-owned Salem plant.plant and the total capital expenditures for the fully consolidated CENG nuclear plants.
ComEd, PECO, BGE, Pepco, DPL and ACEUtility Registrants
Utility Operations
Service Territories and Franchise Agreements
The following table presents the size of service territories, populations of each service territory and the number of customers within each service territory for the Utility Registrants as of December 31, 2017:2018:
| | | Service Territories | | Service Territory Population | | Number of Customers | Service Territories | | Service Territory Population | | Number of Customers |
| (in square miles) | | (in millions) | | (in millions) | (in square miles) | | (in millions) | | (in millions) |
| Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas | Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas | | Total | | Electric | | Natural gas |
ComEd | 11,400 |
| | 11,400 |
| | n/a |
| | 9.4 |
| (a) | 9.4 |
| | n/a |
| | 4.0 |
| | 4.0 |
| | n/a |
| 11,400 |
| | 11,400 |
| | n/a |
| | 9.5 |
| (a) | 9.5 |
| | n/a |
| | 4.0 |
| | 4.0 |
| | n/a |
|
PECO | 2,100 |
| | 1,900 |
| | 1,900 |
| | 4.0 |
| (b) | 4.0 |
| | 2.4 |
| | 1.6 |
| | 1.6 |
| | 0.5 |
| 2,100 |
| | 1,900 |
| | 1,900 |
| | 4.0 |
| (b) | 4.0 |
| | 2.5 |
| | 1.7 |
| | 1.6 |
| | 0.5 |
|
BGE | 3,250 |
| | 2,300 |
| | 3,050 |
| | 3.1 |
| (c) | 3.0 |
| | 2.9 |
| | 1.3 |
| | 1.3 |
| | 0.7 |
| 3,250 |
| | 2,300 |
| | 3,050 |
| | 3.1 |
| (c) | 3.0 |
| | 2.9 |
| | 1.3 |
| | 1.3 |
| | 0.7 |
|
Pepco | 640 |
| | 640 |
| | n/a |
| | 2.4 |
| (d) | 2.4 |
| | n/a |
| | 0.9 |
| | 0.9 |
| | n/a |
| 640 |
| | 640 |
| | n/a |
| | 2.4 |
| (d) | 2.4 |
| | n/a |
| | 0.9 |
| | 0.9 |
| | n/a |
|
DPL | 5,400 |
| | 5,400 |
| | 275 |
| | 1.4 |
| (e) | 1.4 |
| | 0.6 |
| | 0.5 |
| | 0.5 |
| | 0.1 |
| 5,400 |
| | 5,400 |
| | 275 |
| | 1.4 |
| (e) | 1.4 |
| | 0.6 |
| | 0.5 |
| | 0.5 |
| | 0.1 |
|
ACE | 2,800 |
| | 2,800 |
| | n/a |
| | 1.1 |
| (f) | 1.1 |
| | n/a |
| | 0.6 |
| | 0.6 |
| | n/a |
| 2,800 |
| | 2,800 |
| | n/a |
| | 1.1 |
| (f) | 1.1 |
| | n/a |
| | 0.6 |
| | 0.6 |
| | n/a |
|
__________
| |
(a) | Includes approximately 2.7 million in the city of Chicago. |
| |
(b) | Includes approximately 1.6 million in the city of Philadelphia. |
| |
(c) | Includes approximately 0.6 million in the city of Baltimore. |
| |
(d) | Includes approximately 0.7 million in the District of Columbia. |
| |
(e) | Includes approximately 0.1 million in the city of Wilmington. |
| |
(f) | Includes approximately 0.1 million in the city of Atlantic City. |
The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas) and ACE's rights are generally non-exclusive; while PECO's, BGE's (electric) Pepco's and DPL's rights are generally exclusive. Certain authorizations are perpetual while others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the authorizations prior to their expirations.
Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects of the business. The following table outlines the state commissions responsible for utility oversight.
|
| | |
Registrant | | Commission |
ComEd | | ICC |
PECO | | PAPUC |
BGE | | MDPSC |
Pepco | | DCPSC/MDPSC |
DPL | | DPSC/MDPSC |
ACE | | NJBPU |
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE and DPL. Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential disruptions from cyber and physical security breaches.
Seasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand for either summer cooling or winter heating. For PECO, BGE and DPL, natural gas distribution volumes are generally higher during the winter months when cold temperatures create demand for winter heating.
ComEd, BGE, Pepco and DPL Maryland have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result, ComEd’s, BGE’s, Pepco’s and DPL’s Maryland electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by delivery volumes. PECO’s electric distribution revenues and natural gas distribution revenues and ACE’s electric distribution revenues and DPL’s Delaware electric distribution and natural gas revenues are impacted by delivery volumes.
Electric and Natural Gas Distribution Services
The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. PECO's, BGE’s and DPL's electric and gas distribution costs and Pepco's and ACE's electric distribution costs are recovered through traditional rate case proceedings. In certain instances, the Utility Registrants use specific recovery mechanisms as approved by their respective regulatory agencies.
ComEd, Pepco and ACE customers have the choice to purchase electricity, and PECO, BGE and DPL customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. The Utility Registrants remain the distribution service providers for all customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in their respective service areas who do not choose a competitive electric generation supplier. PECO and BGE also retain significant default service obligations to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas, DPL does not retain default service obligations.
For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and therefore do not record Operating revenues or Purchased power and fuel
expense related to the electricity and/or natural gas. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations for further information. For customers that choose to purchase electric generation or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas procurement costs without mark-up and therefore record equal and offsetting amounts of Operating revenues and Purchased power and fuel expense related to the electricity and/or natural gas. As a result, fluctuations in electricity or natural gas sales and procurement costs
have no impact on the Utility Registrants’ Revenues net of purchased power and fuel expense, which is a non-GAAP measure used to evaluate operational performance, or Net Income.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas distribution services.
Procurement-Related Proceedings
The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.
PECO's, BGE’s and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE and DPL have annual firm supply and transportation contracts of 132,000 mmcf, 128,000 mmcf and 58,000 mmcf, respectively. In addition, to supplement gas supply at times of heavy winter demands and in the event of temporary emergencies, PECO, BGE and DPL have available storage capacity from the following sources:
|
| | | | | | | | |
| Peak Natural Gas Sources (in mmcf) |
| Liquefied Natural Gas Facility | | Propane-Air Plant | | Underground Storage Service Agreements (a) |
PECO | 1,200 |
| | 150 |
| | 18,000 |
|
BGE | 1,056 |
| | 550 |
| | 22,000 |
|
DPL | 257 |
| | n/a |
| | 3,800 |
|
___________ | |
(a) | Natural gas from underground storage represents approximately 28%, 46%54% and 34% of PECO's, BGE’s and DPL's 2017-20182018-2019 heating season planned supplies, respectively. |
PECO, BGE and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE and DPL make these sales as part of a program to balance its supply and cost of natural gas. The off-system gas sales are not material to PECO, BGE and DPL.
Refer toSee ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price, for furtheradditional information regarding Utility Registrants' contracts to procure electric supply and natural gas.
Energy Efficiency Programs
The Utility Registrants are allowed to recover costs associated with energy efficiency and demand response programs. Each commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak demand. The programs are designed to meet standards required by each respective regulatory agency.
The Utility Registrants are allowed to earn a return on their energy efficiency costs. See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for furtheradditional information.
Capital Investment
The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas transportation and distribution facilities, to ensure the adequate capacity, reliability and efficiency of their systems. ComEd's, PECO's, BGE's, Pepco's, DPL's and ACE's most recent estimates of capital expenditures for plant additions and improvements for 20182019 are as follows:
|
| | | | | | | | | | | | | | | |
| Projected 2018 Capital Expenditure Spending |
(in millions) | Transmission | | Distribution | | Gas | | Total |
ComEd | $ | 375 |
| | $ | 1,750 |
| | N/A |
| | $ | 2,125 |
|
PECO | 125 |
| | 450 |
| | $ | 225 |
| | 800 |
|
BGE | 175 |
| | 425 |
| | 400 |
| | 1,000 |
|
Pepco | 125 |
| | 600 |
| | N/A |
| | 725 |
|
DPL | 150 |
| | 200 |
| | 50 |
| | 400 |
|
ACE | 175 |
| | 200 |
| | N/A |
| | 375 |
|
ComEd, PECO, BGE, Pepco and DPL have AMI smart meter and smart grid deployment programs within their respective service territories to enhance their distribution systems. PECO, BGE, Pepco and DPL have completed the installation and activation of smart meters and smart grid in their respective service territories. ComEd expects to complete its smart meter and smart grid deployment in 2018. |
| | | | | | | | | | | |
| Projected 2019 Capital Expenditure Spending |
(in millions) | Transmission | | Distribution | | Gas | | Total |
ComEd | 325 |
| | 1,550 |
| | N/A |
| | 1,875 |
|
PECO | 125 |
| | 600 |
| | 250 |
| | 975 |
|
BGE | 225 |
| | 475 |
| | 400 |
| | 1,100 |
|
Pepco | 75 |
| | 650 |
| | N/A |
| | 725 |
|
DPL | 100 |
| | 200 |
| | 50 |
| | 350 |
|
ACE | 150 |
| | 150 |
| | N/A |
| | 300 |
|
Transmission Services
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and wholesale merchant employees.
PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of their transmission facilities to PJM, and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service.
ComEd's transmission rates are established based on a formula that was approved by FERC in January 2008. BGE's, Pepco's, DPL's and ACE's transmission rates are established based on a formula that was approved by FERC in April 2006. FERC’s orders establish the agreed-upon treatment of costs and revenues in the determination of network service transmission rates and the process for updating the formula rate calculation on an annual basis.
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission ratesrate and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The new formula was accepted by FERC effective as of December 1, 2017, subject to refund and set the matter for hearing and settlement judge proceedings, which are currently ongoing. procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge.
See Note 3
4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional detailinformation regarding the PECO transmission formula late.
See Note 3 — Regulatory Matters, Note 25—Segment Information of the Combined Notes to Consolidated Financial Statementsrate and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources for additional information regarding transmission services.
Employees
As of December 31, 2017,2018, Exelon and its subsidiaries had 34,62133,383 employees in the following companies, of which 11,84511,372 or 34% were covered by collective bargaining agreements (CBAs):
| | | IBEW Local 15(a) | | IBEW Local 614(b) | | Other CBAs | | Total Employees Covered by CBAs | | Total Employees | IBEW Local 15(a) | | IBEW Local 614(b) | | Other CBAs | | Total Employees Covered by CBAs | | Total Employees |
Generation(c) | 1,660 |
| | 97 |
| | 2,729 |
| | 4,486 |
| | 15,011 |
| 1,568 |
| | 84 |
| | 2,485 |
| | 4,137 |
| | 14,110 |
|
ComEd | 3,515 |
| | — |
| | — |
| | 3,515 |
| | 6,280 |
| 3,378 |
| | — |
| | — |
| | 3,378 |
| | 6,152 |
|
PECO | — |
| | 1,148 |
| | — |
| | 1,148 |
| | 2,534 |
| — |
| | 1,381 |
| | — |
| | 1,381 |
| | 2,708 |
|
BGE(d) | — |
| | — |
| | — |
| | — |
| | 3,022 |
| — |
| | — |
| | — |
| | — |
| | 3,025 |
|
PHI(e) | — |
| | — |
| | 322 |
| | 322 |
| | 1,320 |
| — |
| | — |
| | 277 |
| | 277 |
| | 1,258 |
|
Pepco(e) | — |
| | — |
| | 1,151 |
| | 1,151 |
| | 1,582 |
| — |
| | — |
| | 1,023 |
| | 1,023 |
| | 1,423 |
|
DPL(e) | — |
| | — |
| | 688 |
| | 688 |
| | 944 |
| — |
| | — |
| | 684 |
| | 684 |
| | 940 |
|
ACE(e) | — |
| | — |
| | 421 |
| | 421 |
| | 647 |
| — |
| | — |
| | 386 |
| | 386 |
| | 612 |
|
Other(f)(g) | 65 |
| | — |
| | 49 |
| | 114 |
| | 3,281 |
| 62 |
| | — |
| | 44 |
| | 106 |
| | 3,155 |
|
Total | 5,240 |
|
| 1,245 |
|
| 5,360 |
|
| 11,845 |
|
| 34,621 |
| 5,008 |
|
| 1,465 |
|
| 4,899 |
|
| 11,372 |
|
| 33,383 |
|
__________
| |
(a) | A separate CBA between ComEd and IBEW Local 15 covers approximately 6573 employees in ComEd’s System Services Group and was renewedwill expire in 2016.2020. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022. |
| |
(b) | PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power, an operating unit of Generation, has an agreement covering 9784 employees, which was renewed in 2016 and expiringexpires in 2019. |
| |
(c) | During 2018, Generation acquired and finalized its CBA with Distrigas Local 369, which will expire in 2020, and additionally, finalized a first collective bargaining agreement, expiring in 2021, with a small unit of employees represented by IUOE Local 501 at Exelon's Hyperion Solutions facility. Also in 2018, Generation finalized a three-year agreement with the Security Officer union at Braidwood and that CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at FitzPatrick into one CBA covering both craft and security employees, which will expire in 2023. During 2016, Generation finalized its CBA with the Security Officer union at Oyster Creek, expiring in 2022 and New Energy IUOE Local 95-95A, which will expire in 2021. Also, during 2016, Generation finalized a 5-year agreement with the New England ENEH, UWUA Local 369, which will expire in 2022. During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and fourthree Security Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 20182019 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively andrespectively. Also in 2014, CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018. |
| |
(d) | In January 2017, an election was held at BGE which resulted in union representation for 1,394certain employees, who numbered 1,284 at the end of the year.2018. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. |
| |
(e) | PHI’s utility subsidiaries are parties to five CBAs with four local unions. CBAs are generally renegotiated every three to five years. All of these CBAs were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020. During 2018, ACE finalized a five-year agreement with Local 210, expiring in 2023. |
| |
(f) | Other includes shared services employees at BSC. |
Environmental Regulation
General
The Registrants are subject to comprehensive and complex legislation regarding environmental matters by the federal government and various state and local jurisdictions in which they operate their facilities. The Registrants are also subject to environmental regulations administered by the EPA and various state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water, and solid and hazardous waste disposal.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address environmental compliance and strategy, including the CEO; the Senior Vice
President, Corporate Strategy & Chief Innovation and Chief Sustainability Officer; the Senior Vice President, Competitive Market Policy; and the Director, Safety & Sustainability, as well as senior management of Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate Governance Committee the authority to oversee Exelon’s compliance with health, environmental and safety laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as discussed in further detail below. The respective Boards of ComEd, PECO, BGE, Pepco, DPL and ACE oversee environmental, health and safety issues related to these companies.
Air Quality
Air quality regulations promulgated by the EPA and the various state and local environmental agencies impose restrictions on emission of particulates, sulfur dioxide (SO2)(SO2), nitrogen oxides (NOx)(NOx), mercury and other air pollutants and require permits for operation of emitting sources. Such permits have been obtained as needed by Exelon’s subsidiaries. However, due to its low emitting generation fleet comprised of nuclear, natural gas, hydroelectric, wind and solar, compliance with the Federal Clean Air Act does not have a material impact on Generation’s operations.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information regarding clean air regulation in the forms of the CSAPR, the regulation of hazardous air pollutants from coal- and oil-fired electric generating facilities under MATS, and regulation of GHG emissions.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Section 316(b) of the Clean Water Act
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All 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 recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Mountain Creek, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities Riverside and Salem.
On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.
Pursuant to discussions with the NJDEP in 2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek by December 31, 2019, ten years before the expiration of its operating license in 2029. The agreement only applies toOn September 17, 2018, Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance requirements for Section 316(b) at Exelon’s other plants. On February 2, 2018, Exelon announced that Generation will permanently ceaseceased generation operations, atand its cooling water intake system is no longer subject to Section 316(b). See Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information about the sale and decommissioning of Oyster Creek at the end of its current operating cycle in October 2018.Creek.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement most likely to support cooling towers). The R.E Ginna, and Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits in 2014 and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.
Salem
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Solid and Hazardous Waste
CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Delaware, Illinois, Maryland, New Jersey and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.
Environmental Remediation
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 20182019 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $48$46 million, consisting of $42$36 million, $6 million and $6$4 million at ComEd, PECO and PECOBGE respectively. The Utility Registrants also have contingent liabilities for
environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2017,2018, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws.
In addition, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Notes 3Note 4 — Regulatory Matters and 23Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ results of operations, cash flows and financial positions.Consolidated Financial Statements.
Global Climate Change
Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns ornor operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2.CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. In 2017, whileAs of December 31, 2018, fossil fuel poweredgeneration represented approximately 33 percent29% of Exelon's owned generating capacity, while fossil fuel-fired generation representsduring 2018 represented less than 12 percent11% of Exelon's overall generation on a MWh basis. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6)(SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.
Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
International Climate Change Agreements.At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated.
Federal Climate Change Legislation and Regulation.It is highly unlikely whetherthat federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. More importantly, continuedContinued inaction could negatively impact the value of Exelon’s low-carbon fleet.
Under the Obama Administration, the EPA proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are currently being litigated. However,Under the Trump Administration, hason October
16, 2017 the EPA proposed to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a repealbest system of emissions reduction (BSER) for existing power plants. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the Clean Power Plan, and is expected to seek broad public commentCPP with revised emission guidelines based on whether and how to regulate GHGs atheat rate improvement measures that could be achieved within the federal level. Details are not yet known and are likely to be further informed by the public comment process.fence line of existing power plants.
Given thislitigation uncertainty and the absence of a final ACE rule, Exelon and Generation cannot at this time predict the futureimpacts of the Clean Power Plan, or its repeal and/or replacement,regulation of existing power plants, or individual state responses to Clean Power Plan developments related to final resolution of the CPP and ACE regulations, or how developments will impact their future results of operations, cash flows and financial positions.
statements.
Regional and State Climate Change Legislation and Regulation.A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on what, if anything, replacesresolution of the Clean Power PlanCPP and ACE regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and IllinoisNew Jersey adopted standards targeted at preserving the zero-carbon attributes of certain Exelon’s nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within boththese states. Other states in which Generation and our utilities operate are considering similar programs.
See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
Executive Officers of the Registrants as of February 9, 20188, 2019
Exelon
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Crane, Christopher M. | | 5960 |
| | Chief Executive Officer, ExelonExelon; | | 2012 - Present |
| | | | Chairman, ComEd, PECO & BGE | | 2012 - Present |
| | | | Chairman, PHI | | 2016 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | President, Generation | | 2008 - 2013 |
| | | | | | |
Cornew, Kenneth W. | | 5253 |
| | Senior Executive Vice President and Chief Commercial Officer, ExelonExelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
O’Brien, Denis P.Pramaggiore, Anne R. | | 5760 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 20122018 - Present |
| | | | Vice Chairman, ComEd, PECO & BGE | | 2012 - Present |
| | | | Vice Chairman, PHI | | 2016 - Present |
| | | | | | |
Pramaggiore, Anne R. | | 59 |
| | Chief Executive Officer, ComEd | | 2012 - Present2018 |
| | | | President, ComEd | | 2009 - Present2018 |
| | | | | | |
Adams, Craig L.Dominguez, Joseph | | 6556 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - Present2018 |
| | | | | | |
Butler, Calvin G. | | 4849 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Velazquez, David M. Velazquez | | 5859 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL &and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
Von Hoene Jr., William A. | | 6465 |
| | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
Thayer, Jonathan W.Nigro, Joseph | | 4654 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 20122018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
Aliabadi, Paymon | | 5556 |
| | Executive Vice President and Chief Risk Officer, Exelon | | 2013 - Present |
| | | | Managing Director, Gleam Capital Management | | 2012 - 2013 |
| | | | | | |
DesParte, Duane M. |
| | | | | | | |
Name | | 54Age |
| | Position | | Period |
Souza, Fabian E. | | 48 |
| | Senior Vice President and Corporate Controller, Exelon | | 20082018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
| | | | Vice President, Internal Audit and Advisory Services, The AES Corporation | | 2014 - 2015 |
| | | | Deputy Corporate Controller, The AES Corporation | | 2014 - 2014 |
| | | | Assistant Corporate Controller, Global Controllership, The AES Corporation | | 2013 - 2014 |
| | | | Controller, Global Utilities, The AES Corporation | | 2011 - 2013 |
Generation
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Cornew, Kenneth W. | | 5253 |
| | Senior Executive Vice President and Chief Commercial Officer, ExelonExelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pacilio, Michael J. | | 5758 |
| | Executive Vice President and Chief Operating Officer, Exelon Generation | | 2015 - Present |
| | | | President, Exelon Nuclear; Senior Vice President | | 2010 - 2015 |
| | | | and Chief Nuclear Officer, Generation | | |
| | | | | | |
Hanson, Bryan C | | 5253 |
| | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation | | 2015 - Present |
| | | | | | |
Nigro, JosephMcHugh, James | | 5347 |
| | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 20132018 - Present |
| | | | Senior Vice President, Portfolio Management and& Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 20132016 |
| | | | | | |
DeGregorio, RonaldBarnes, John | | 55 |
| | Senior Vice President, Generation; President, Exelon Power | | 2018 - Present |
| | | | Senior Vice President, Generation, Senior Vice President and Chief Operating Officer, Exelon Power | | 2012 - Present2018 |
| | | | | | |
Wright, Bryan P. | | 5152 |
| | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | Senior Vice President, Corporate Finance, Exelon | | 2012 - 2013 |
| | | | | | |
Bauer, Matthew N. | | 4142 |
| | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | Vice President of Power Finance, Exelon Power | | 2012 - 2014 |
ComEd
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Pramaggiore, Anne R.Dominguez, Joseph | | 5956 |
| | Chief Executive Officer, ComEd | | 20122018 - Present |
| | | | Executive Vice President, ComEdGovernmental & Regulatory Affairs and Public Policy, Exelon | | 20092015 - Present2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Donnelly, Terence R. | | 5758 |
| | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - Present2018 |
| | | | | | |
Trpik Jr., Joseph R.Jones, Jeanne M. | | 4839 |
| | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 20092018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | Director, Finance, Exelon Nuclear | | 2013 - 2014 |
| | | | | | |
Jensen, ValPark, Jane | | 6246 |
| | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | Chief of Staff to President and Chief Executive Officer, ComEd | | 2012 - Present2014 |
| | | | | | |
Gomez, Veronica | | 4849 |
| | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
Marquez Jr., Fidel | | 5657 |
| | Senior Vice President, Governmental &and External Affairs, ExelonComEd | | 2012 - Present |
| | | | | | |
McGuire, Timothy M. | | 5960 |
| | Senior Vice President, Distribution Operations, ComEd | | 2016 - Present |
| | | | Vice President, Transmission and Substations, ComEd | | 2010 - 2016 |
| | | | | | |
Kozel, Gerald J. | | 4546 |
| | Vice President, Controller, ComEd | | 2013 - Present |
| | | | Assistant Corporate Controller, Exelon | | 2012 - 2013 |
PECO
|
| | | | | | | |
Name | | Age | | Position | | Period |
Adams, Craig L.Innocenzo, Michael A. | | 6553 |
| | President and Chief Executive Officer, PECO | | 20122018 - Present |
| | | | | | |
Barnett, Phillip S. | | 54 |
| | Senior Vice President and Chief Financial Officer, PECO | | 2007 - Present |
| | | | Treasurer, PECO | | 2012 - Present |
| | | | | | |
Innocenzo, Michael A. | | 52 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
McDonald, John | | 61 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, Pepco Holdings | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
Stefani, Robert J. | | 44 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | Director, Corporate Development, Exelon | | 2012 - 2015 |
| | | | | | |
Murphy, Elizabeth A. | | 5859 |
| | Senior Vice President, Governmental &and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental &and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
Webster Jr., Richard G. | | 5657 |
| | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
Jiruska, Frank J.Feldhake, Lauren | | 5753 |
| | Vice President, Customer Operations, PECO | | 20132017 - Present |
| | | | Director, Customer Care, PECO | | 2014 - 2017 |
| | | | Director, Customer Financial Operations, PECO | | 2009 - 2014 |
| | | | | | |
Diaz Jr., Romulo L. | | 7172 |
| | Vice President and General Counsel, PECO | | 2012 - Present |
| | | | | | |
Bailey, Scott A. | | 4142 |
| | Vice President and Controller, PECO | | 2012 - Present |
BGE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Butler, Calvin G. | | 4849 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Woerner, Stephen J. | | 5051 |
| | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | Senior Vice President, BGE | | 2009 - 2014 |
| | | | | | |
Vahos, David M. | | 4546 |
| | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | Vice President and Controller, BGE | | 2012 - 2014 |
| | | | | | |
Núñez, Alexander G. | | 4647 |
| | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - Present |
| | | | Vice President, Governmental &and External Affairs, BGE | | 2013 - 2016 |
| | | | Director, State Affairs, BGE | | 2012 - 2013 |
| | | | | | |
Case, Mark D. | | 5657 |
| | Vice President, Strategy and Regulatory Policy and Strategy,Affairs, BGE | | 2012 - Present |
| | | | | | |
Biagiotti, Robert D.Oddoye, Rodney | | 4842 |
| | Vice President, Customer Operations, BGE | | 20152018 - Present |
| | | | Vice President, Gas Distribution,Director, Northeast Regional Electric Operations, BGE | | 20112016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | Manager, Distribution Operations, BGE | | 2013 - 2015 |
| | | | | | |
Gahagan, Daniel P.Corse, John | | 6458 |
| | Vice President and General Counsel, BGE | | 20072018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
| | | | | | |
Holmes, Andrew W. Holmes | | 4950 |
| | Vice President and Controller, BGE | | 2016 - Present |
| | | | Director, Generation Accounting, Exelon | | 2013 - 2016 |
| | | | Director, Derivatives and Technical Accounting, Exelon | | 2008 - 2013 |
PHI, Pepco, DPL and ACE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Velazquez, David M. | | 5859 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009-20162009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL &and ACE | | 2009 - Present |
| | | | | | |
Anthony, J. Tyler | | 5354 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL &and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
Kinzel, Donna J.Barnett, Phillip S. | | 5055 |
| | Senior Vice President, Chief Financial Officer and Treasurer PHI, Pepco, DPL &and ACE | | 2016 - Present |
| | | | Vice President, Treasurer and Chief Risk Officer, Pepco Holdings | | 2012 - 2016 |
| | | | | | |
Bonney, Paul R. | | 59 | | Senior Vice President, Legal and Regulatory Strategy, PHI, Pepco, DPL & ACE | | 20162018 - Present |
| | | | Senior Vice President and General Counsel, ConstellationChief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 20162018 |
| | | | | | |
Lavinson, Melissa A. | | 4849 |
| | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL &and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | Vice President, Federal Affairs, PG&E Corporation | | 2012 - 2015 |
| | | | | | |
Stark, Wendy E. | | 4546 |
| | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco DPL &and ACE | | 2016 - Present2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - Present |
| | | | | | |
McGowan, Kevin M. | | 5657 |
| | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL &and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
Aiken, Robert M. | | 5152 |
| | Vice President and Controller, PHI, Pepco, DPL &and ACE | | 2016 - Present |
| | | | Vice President and Controller, Generation | | 2012 - 2016 |
Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond that Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC), which comprises officers of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon Board of Directors and the ComEd, PECO, BGE and PHI boardsBoards of directors.Directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors evaluates risks related to the generation business. The risk factors discussed below could adversely affect one or more of the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements and the market prices of their publicly traded securities. Each of the Registrants has disclosed the known material risks that affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed by a Registrant to be material that could adversely affect its performance or financial condition in the future.
Exelon's results of operations, cash flows andconsolidated financial positionstatements are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions
and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United States. Factors that affect the results of operations, cash flows orconsolidated financial positionsstatements of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:
Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies.technologies and business models.
Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility regulatory business model cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.
Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.
Risks Related to the PHI Merger.Exelon is subject to additional risks related to the merger with PHI, which closed on March 23, 2016.
A discussion of each of these risk categories and other risk factors is included below.
Market and Financial Factors
Generation is exposed to depressed prices in the wholesale and retail power markets, which could negatively affect its results of operations, cash flows orconsolidated financial positionstatements (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels
Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit. Often, the next unit of electricity will be supplied from generating stations fueled by fossil fuels. Consequently, changes in the market price of fossil fuels often result in comparable changes to the market price of power. For example, the use of technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing downward pressure on natural gas prices and, therefore, on power prices. The continued addition of supply from new alternative generation resources, such as wind and solar, whether mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation, could displace a higher marginal cost plant, further reducing power prices. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of pollution from fossil fuel generation is not factored into market prices.
Demand and Supply
Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on electricity market prices. The tepid economic environment in recent years and growing energy efficiency and demand response initiatives have limited the demand for electricity in Generation’s markets. In addition, in some markets, the supply of electricity through wind or solar generation, when combined with other base-load generation such as nuclear, could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Exelon's nuclear plants. Increased supply in excess of demand is furthered by the continuation of RPS mandates and subsidies for renewable energy.
Retail Competition
Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.
Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positionsstatements and such impacts could be
emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon's and Generation's result of operations through accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operating and maintenance expenses. A slow recovery in market conditions could result in a prolonged depression of or further decline in commodity prices, including low forward natural gas and power prices and low market volatility, which could also adversely affect Exelon’s and Generation’s results of operations, cash flows or financial positions. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
In addition to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and could negatively affect its results of operations (Exelon and Generation).
Credit Risk
Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Market Designs
Designs. The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry, including technologies related to energy generation, distribution and consumption (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, cost-effective renewable energy technologies, energy efficiency, distributed generation and energy
storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities
obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility Registrants' customers, the results of operations, cash flows orconsolidated financial positionsstatements of the Utility Registrants could be negatively affected. Ultimately, if the Registrants are unable to manage the investments within the NDT funds and benefit plan assets and are unable to manage the related benefit plan liabilities and the related asset retirement obligations, their results of operations, cash flows orconsolidated financial positionsstatements could be negatively impacted.
Unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could negatively impact the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations. Disruptions in the capital and credit markets in the United States or abroad could adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital
expenditures, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash.
In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2017,2018, approximately 19%, or $1.8 billion, 19%, or $1.8 billion, and 17%18%, or $1.6$1.7 billion of the Registrants’ available credit facilities were with European, Canadian and Asian banks, respectively. The credit facilities include $9.5$9.7 billion (including bilateral credit facilities and credit facilities for project
finance) in aggregate total commitments of which $8.3$8.0 billion was available as of December 31, 2017.2018. As of December 31, 2017,2018, there were no borrowings under Generation's bilateral credit facilities. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positions.statements.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation. Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy on such arrangements may be a significant assumption in performing impairment assessments of the project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market
prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.
A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for furtheradditional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s financial performance could be negatively affected by price volatility, availability and other risk factors associated with the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the results of operations, cash flows orconsolidated financial positionstatements for Generation.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its business results of operations, cash flows or consolidated financial position.statements.
Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could impact the Registrants’ results of operations, cash flows orconsolidated financial positions.statements. (All Registrants).
Corporate Tax Reform
Reform. On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA, further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future results of operations, cash flows orconsolidated financial positions.
In addition, as allowed under SEC Staff Accounting Bulletin No. 118 (SAB 118), the Registrants have recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants’ financial statements, but reasonable estimates could be determined. However, the provisional amounts may change as the Registrants finalize their analysis and computations and such changes could be material to the Registrants’ future results of operations, cash flows or financial positions.statements.
The Utility Registrants have made their best estimate regarding the probability and timing of settlements of net regulatory liabilities established pursuant to the TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could
have a material impact on the Utility Registrants’ future results of operations, cash flows orconsolidated financial positions.statements.
Tax reserves
reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates, including increases in the cost of purchased power and increases in natural gas prices for the Utility Registrants, and the impact of economic downturns could lead to greater expense for uncollectible customer balances. Additionally, increased rates could lead to decreased volumes delivered. Both of these factors could decrease Generation’s and the Utility Registrants' results from operations, cash flows or financial positions (All Registrants).
The impacts of economic downturns on the Utility Registrants' customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances', which would negatively affect the Utility Registrants' results of operations, cash flows orconsolidated financial positions.statements. Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances which could negatively affect Generation's results of operations, cash flows orconsolidated financial position.statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for further discussionadditional information of the Registrants’ credit risk.
The Utility Registrants' current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s, PECO’s and ACE's costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas could result in declines in customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challenges by the regulators or the Utility Registrants as to the recoverability of these costs could have a material adverse effect onin the Registrants’ results of operations, cash flows orconsolidated financial positions.statements. Also, the Utility Registrants' cash flows could be adversely affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
The effects of weather could impact the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues
at PECO, DPL Delaware and ACE. Due to revenue decoupling,
BGE, Pepco and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period, and are not affected by actual weather with the exception of major storms. Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. These extreme conditions could have detrimental effects onin the Utility Registrants' results of operations, cash flows orconsolidated financial positions.statements. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Certain long-lived assets and other assets recorded on the Registrants’ statements of financial position could become impaired, which would result in write-offs of the impaired amounts (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. Specifically, long-lived assets account for 64%, 51%, 70%, 79%, 84%, 77%, 82% and 79% of total assets for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of December 31, 2017. In addition, Exelon and Generation have significant balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assets for potential impairment. An impairment would require the Registrants to reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact onin the Registrants’ results of operations, cash flows orconsolidated financial positions.statements.
As of December 31, 2017,2018, Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in 2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.
Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, PHI’s, and ComEd’s goodwill, which could be material.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, and Note 6 — Property, Plant and Equipment, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 10 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional discussioninformation on long-lived asset and goodwill impairments.
Exelon and its subsidiaries at times guarantee the performance of third parties, which could result in substantial costs in the event of non-performance by such third parties. In addition, the Registrants could have rights under agreements which obligate third parties to indemnify the Registrants for various obligations, and the Registrants could incur substantial costs in the event that the applicable Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection with the acquisition and divestiture of assets (All Registrants).
Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees. Such performance guarantees could have a material impact onin the results of operations, cash flows orconsolidated financial positionstatements of the Registrant. Some of the Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities and such costs could adversely affect a Registrant’s results of operations, cash flows orconsolidated financial position.statements.
Some of the Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations, which could adversely impact that Registrant’s results of operations, cash flows orconsolidated financial position.statements. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee may have agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO and BGE may have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation or the transferee of Pepco's, DPL's or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims, which could impact that Utility Registrant's results of operations, cash flows orconsolidated financial position.statements. In addition, the Utility Registrants may have residual liability under certain laws in connection with their former generation facilities. For example, under CERCLA, former owners of property may retain certain liability for environmental claims and remediation. The third parties to whom the Utility Registrants transferred their former generation facilities may have agreed to indemnify the Utility Registrants for all or a portion
of such liability but if such third parties fail or are unable to perform under the indemnity, the applicable Utility Registrant may be liable for certain remediation costs.
Regulatory and Legislative Factors
The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to regulatory and legislative actions that adversely affect their results of operations, cash flows orconsolidated financial positions.statements. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations, cash flows or financial results (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positionsstatements are significantly affected by Generation's sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s and the Utility Registrants' results of operations, cash flows orconsolidated financial positionsstatements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations and could negatively impact their respective results of operations, cash flows orconsolidated financial positions.statements.
State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information, resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positions. Various legislative and regulatory proposals to address climate change through GHG emission reductions, if enacted, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase the market price at which all generators in a region, including Generation, could sell their output, thereby increasing the revenue Generation could realize from its low-carbon nuclear assets. Conversely, existing or new regulations intended to reduce GHG emissions could be rolled back, allowing fossil fueled facilities which were otherwise scheduled to retire to continue to operate if economical. This could result in decreases in market prices thereby reducing Generation’s revenues. However, national regulation or legislation addressing climate change through an RPS could also increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices for electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derive from Generation’s nuclear assets under a carbon constrained regulatory regime that might exist in the future. Similarly, final regulations under Section 111(d) of the Clean Air Act may not provide sufficient incentives for states to utilize carbon-free nuclear power as a means of meeting GHG reduction requirements, while continuing a policy of favoring renewable energy sources. Current state level climate change and renewable regulation is already providing incentives for regional wind development.statements. The Registrants cannot predict when or whether any of these various legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Legislative and regulatory efforts in Illinois, New York and New YorkJersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through zero emission credit programs are subject to legal challenges and, if overturned, could negatively impact Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positionsstatements and result in the early retirement of certain of Generation’s nuclear plants.
Generation could be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and functioning of the wholesale markets (Exelon and Generation).
Federal and state legislative and regulatory bodies are facing pressures to address consumer concerns, or are themselves raising concerns, that energy prices in wholesale markets are too high or insufficient generation is being built because the competitive model is not working and, therefore, are considering some form of re-regulation or some other means of reducing wholesale market prices or subsidizing new generation. Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.
Approximately 61%63% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for, policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.
FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities. Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other type of covered financial entity.
There are some rulemaking proceedings that have not yet been finalized, in particular, proposed rules on position limits that would apply to both Exchange-traded futures contracts and economically-equivalent over-the-counter swaps. It is possible that those rules will be finalized by the end of 2018. Although the company would incur some costs associated with monitoring and compliance with such rules, it does not expect the rules to have a material impact on its business operations.
The Utility Registrants could also be subject to some Dodd-Frank requirements to the extent they were to enter into swaps. However, at this time, management of the Utility Registrants continue to expect that their companies will not be materially affected by Dodd-Frank.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased
costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.
If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.
In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person
could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.
In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval.
The Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs or earn an adequate return and could have a material adverse effect onin the Utility Registrants' results of operations, cash flows orconsolidated financial positions.statements. See Note 34 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the results of operations, cash flows orconsolidated financial positionsstatements of Generation and the Utility Registrants (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources such as wind, solar, biomass and geothermal, could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs for RECs and purchased power and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact the Utility Registrants if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.
The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon and the Utility Registrants (Exelon and the Utility Registrants).
As of December 31, 2017,2018, Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See NotesNote 1 — Significant Accounting Policies, 3Note 4 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.
Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change (Exelon and Generation).
Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission
allowance credits. For example, a Federal RPS could increase the cost of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change, seeSee ITEM 1. BUSINESS — Global Climate Change and Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.Statements for additional information regarding climate change.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. As operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the
bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards.
See Note 34 — Regulatory Matters and Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants have large consumer customer bases and as a result could be the subject of public criticism focused on the operability of their assets and infrastructure and quality of their service. Adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs). The imposition of any of the foregoing could have a material negative impact on the Registrants' business results of operations, cash flows or consolidated financial positions.statements.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could negatively impact their results of operations, cash flows orconsolidated financial positionsstatements (All Registrants).
The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures,, result in lost revenue or restrict existing business activities, any of whichcould have a material adverse effect onin the Registrants’ results of operations, cash flows orconsolidated financial positions.statements.
Generation could be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations and profitability of its nuclear generating fleet (Exelon and Generation).
Regulatory risk
risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs and significantly affect Generation’s results of operations, cash flows orconsolidated financial position.statements. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage
storage. The approval of a national repository for the storage of SNF, such as the one previously considered at Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation's results of operations, cash flows orconsolidated financial position. Generation currently estimates 2030 to be the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action.statements. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
Operational Factors
The Registrants’ employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near their operations. As a result, employees, contractors, customers and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters, such as seismic activity, fires resulting from natural causes such as lightning, extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general could adversely affect the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, the Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain, which could adversely affect the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements and their ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected, resulting in decreased service levels and increased costs.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors
factors. Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages
outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality
quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.
Operational risk
risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shut downshutdown the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s results of operations, cash flows orconsolidated financial position.statements. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk
risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect onin Generation’s results of operations, cash flows orconsolidated financial position.statements. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly adversely affect Generation’s results of operations, cash flows orconsolidated financial position.statements.
Nuclear insurance
insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through
mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $13.4$14.1 billion limit for a single incident.
Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional discussioninformation of nuclear insurance.
Decommissioning obligation and funding
funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on
the decommissioning trustNDT funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. No assurance can be given that the costs of such decommissioning will not substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is making contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positionsstatements could be significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s results of operations, cash flows orconsolidated financial positionstatements could be significantly adversely affected. Additionally, if the pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise,Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.
InIf the case ofexpected value in the NDT funds for any nuclear unitsunit subject to the regulatory agreements with the ICC if the funds held in the NDT funds for any former ComEd unit areis expected to not exceed the total decommissioning obligation for that unit, the accounting to offset decommissioning-relateddecommissioning-
related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations
and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations, cash flows orconsolidated financial positionsstatements could be material. Additionally, any remaining balances in noncurrent payables to affiliates at Generation and ComEd’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact on Generation’s Consolidated Statements of Operations and Comprehensive Income.
In the case ofFor the nuclear units subject to the regulatory agreements with the PAPUC, any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations, cash flows andconsolidated financial positionsstatements could be material. Additionally,If the accounting to offset decommissioning-related activities is discontinued, any remaining balances in noncurrent payables to affiliates at Generation and ComEd's or PECO’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact onin Generation’s Consolidated Statement of Operations and Comprehensive Income.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. The license for the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired on September 1, 2014. FERC issued an annual license, effective as of the expiration of the previous license. If FERC does not issue a license prior to the expiration of the annual license, the annual license renews automatically. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, or could result in increased operating costs or could render the project uneconomic and significantly affect Generation’s results of operations, cash flows orconsolidated financial position.statements. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants’ respective results of operations, cash flows orconsolidated financial positionsstatements could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure of electric or gas systems, generation facilities or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS for furtheradditional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' operating costs, and customers’ and regulators’ opinions of the Utility Registrants are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities, including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, the Utility Registrants' results of operations, cash flows orconsolidated financial positionsstatements could be negatively impacted. Furthermore, if
any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, the Utility Registrants' financial results could also be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory oversight and the Utility Registrants' maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, and those damages could be material to ComEd’s results of operations, cash flows orconsolidated financial position.statements.
The Utility Registrants' respective ability to deliver electricity, their operating costs and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
The electricity transmission facilities of the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid that is operated by PJM RTO. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions at other utilities will not cause interruptions in the Utility Registrants’ service areas. If the Utility Registrants were to suffer such a service interruption, it could have a negative impact onin their and Exelon’s results of operations, cash flows andconsolidated financial positions.
statements.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of Exelon or another Registrant and its customer supply activities could be adversely affected, customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its subsidiaries could be subject to legal claims, loss of revenues, increased costs, operations shutdown, etc., any of which could contribute to the loss of customers and have a negative impact on the business and/or results of operations, cash flows orconsolidated financial positions.statements. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. The Utility Registrants' deployment of smart meters throughout their service territories could increase the
risk of damage from an intentional disruption of the system by third parties. In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their results of operations, cash flows orconsolidated financial positions.statements.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ results of operations, cash flows orconsolidated financial positionsstatements (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their results of operations, cash flows orconsolidated financial positionsstatements could be negatively impacted.
The Registrants could make investments in new business initiatives, including initiatives mandated by regulators, and markets that may not be successful, and acquisitions could not achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third
parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into liquefied natural gas. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated Smart Grid and utility of the future initiatives and other non-regulatory mandated initiatives. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity and obsolescence of technology. Due to these risks, no assurance can be given that such initiatives will be successful and will not have a material adverse effect onin the Utility Registrants' results of operations, cash flows orconsolidated financial positions.statements.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts which could impact the Registrants’ results of operations (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the PHI Merger
The merger may not achieve its anticipated results, and Exelon could be unable to integrate the operations of PHI in the manner expected (Exelon and PHI).
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 could 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 and PHI's future business, prospects, results of operations, cash flows or financial conditions.
The merger may not be accretive to earnings and could cause dilution to Exelon’s earnings per share, which could negatively affect the market price of Exelon’s common stock (Exelon).
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, could 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.
|
| |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2017:2018:
| | Station(a) | Region | Location | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Braidwood | Midwest | Braidwood, IL | 2 |
| | | | Uranium | | Base-load | | 2,381 |
| | Midwest | Braidwood, IL | 2 |
| | Uranium | Base-load | 2,386 |
| |
Byron | Midwest | Byron, IL | 2 |
| | | | Uranium | | Base-load | | 2,347 |
| | Midwest | Byron, IL | 2 |
| | Uranium | Base-load | 2,347 |
| |
LaSalle | Midwest | Seneca, IL | 2 |
| | | | Uranium | | Base-load | | 2,320 |
| | Midwest | Seneca, IL | 2 |
| | Uranium | Base-load | 2,320 |
| |
Dresden | Midwest | Morris, IL | 2 |
| | | | Uranium | | Base-load | | 1,845 |
| | Midwest | Morris, IL | 2 |
| | Uranium | Base-load | 1,845 |
| |
Quad Cities | Midwest | Cordova, IL | 2 |
| | 75 |
| | Uranium | | Base-load | | 1,403 |
| (f) | Midwest | Cordova, IL | 2 |
| 75 |
| Uranium | Base-load | 1,403 |
| (e) |
Clinton | Midwest | Clinton, IL | 1 |
| | | | Uranium | | Base-load | | 1,069 |
| | Midwest | Clinton, IL | 1 |
| | Uranium | Base-load | 1,069 |
| |
Michigan Wind 2 | Midwest | Sanilac Co., MI | 50 |
| | 51 |
| | Wind | | Base-load | | 46 |
| (f)(h) | Midwest | Sanilac Co., MI | 50 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Beebe | Midwest | Gratiot Co., MI | 34 |
| | 51 |
| | Wind | | Base-load | | 42 |
| (f)(h) | Midwest | Gratiot Co., MI | 34 |
| 51 |
| Wind | Base-load | 42 |
| (e)(h) |
Michigan Wind 1 | Midwest | Huron Co., MI | 46 |
| | 51 |
| | Wind | | Base-load | | 35 |
| (f)(h) | Midwest | Huron Co., MI | 46 |
| 51 |
| Wind | Base-load | 35 |
| (e)(g) |
Harvest 2 | Midwest | Huron Co., MI | 33 |
| | 51 |
| | Wind | | Base-load | | 30 |
| (f)(h) | Midwest | Huron Co., MI | 33 |
| 51 |
| Wind | Base-load | 30 |
| (e)(g) |
Harvest | Midwest | Huron Co., MI | 32 |
| | 51 |
| | Wind | | Base-load | | 27 |
| (f)(h) | Midwest | Huron Co., MI | 32 |
| 51 |
| Wind | Base-load | 27 |
| (e)(g) |
Beebe 1B | Midwest | Gratiot Co., MI | 21 |
| | 51 |
| | Wind | | Base-load | | 26 |
| (f)(h) | Midwest | Gratiot Co., MI | 21 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Ewington | Midwest | Jackson Co., MN | 10 |
| | 99 |
| | Wind | | Base-load | | 20 |
| (f) | Midwest | Jackson Co., MN | 10 |
| 99 |
| Wind | Base-load | 20 |
| (e) |
Marshall | Midwest | Lyon Co., MN | 9 |
| | 99 |
| | Wind | | Base-load | | 19 |
| (f) | Midwest | Lyon Co., MN | 9 |
| 99 |
| Wind | Base-load | 19 |
| (e) |
City Solar | Midwest | Chicago, IL | 1 |
| | | | Solar | | Base-load | | 9 |
| | Midwest | Chicago, IL | 1 |
| | Solar | Base-load | 9 |
| |
AgriWind | Midwest | Bureau Co., IL | 4 |
| | 99 |
| | Wind | | Base-load | | 8 |
| (f) | |
Cisco | Midwest | Jackson Co., MN | 4 |
| | 99 |
| | Wind | | Base-load | | 8 |
| (f) | |
Solar Ohio | Midwest | Toledo, OH | 2 |
| | | | Solar | | Base-load | | 4 |
| | Midwest | Toledo, OH | 2 |
| | Solar | Base-load | 4 |
| |
Blue Breezes | Midwest | Faribault Co., MN | 2 |
| | | | Wind | | Base-load | | 3 |
| | Midwest | Faribault Co., MN | 2 |
| | Wind | Base-load | 3 |
| |
CP Windfarm | Midwest | Faribault Co., MN | 2 |
| | 51 |
| | Wind | | Base-load | | 2 |
| (f)(h) | Midwest | Faribault Co., MN | 2 |
| 51 |
| Wind | Base-load | 2 |
| (e)(g) |
Southeast Chicago | Midwest | Chicago, IL | 8 |
| | | | Gas | | Peaking | | 296 |
| | Midwest | Chicago, IL | 8 |
| | Gas | Peaking | 296 |
| (k) |
Clinton Battery Storage | Midwest | Blanchester, OH | 1 |
| | | | Energy Storage | | Peaking | | 10 |
| | Midwest | Blanchester, OH | 1 |
| | Energy Storage | Peaking | 10 |
| |
Total Midwest | | | | | | 11,950 |
| | | | | 11,939 |
| |
| | | | | | | | | | | | |
Limerick | Mid-Atlantic | Sanatoga, PA | 2 |
| | | | Uranium | | Base-load | | 2,317 |
| | Mid-Atlantic | Sanatoga, PA | 2 |
| | Uranium | Base-load | 2,317 |
| |
Peach Bottom | Mid-Atlantic | Delta, PA | 2 |
| | 50 |
| | Uranium | | Base-load | | 1,303 |
| (f) | Mid-Atlantic | Delta, PA | 2 |
| 50 |
| Uranium | Base-load | 1,324 |
| (e) |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 2 |
| | 42.59 |
| | Uranium | | Base-load | | 1,007 |
| (f) | Mid-Atlantic | Lower Alloways Creek Township, NJ | 2 |
| 42.59 |
| Uranium | Base-load | 1,002 |
| (e) |
Calvert Cliffs | Mid-Atlantic | Lusby, MD | 2 |
| | 50.01 |
| | Uranium | | Base-load | | 888 |
| (f)(g) | Mid-Atlantic | Lusby, MD | 2 |
| 50.01 |
| Uranium | Base-load | 895 |
| (e)(f) |
Three Mile Island | Mid-Atlantic | Middletown, PA | 1 |
| | | | Uranium | | Base-load | | 837 |
| (k) | Mid-Atlantic | Middletown, PA | 1 |
| | Uranium | Base-load | 837 |
| (j) |
Oyster Creek | Mid-Atlantic | Forked River, NJ | 1 |
| | | | Uranium | | Base-load | | 625 |
| (e) | |
Conowingo | Mid-Atlantic | Darlington, MD | 11 |
| | | | Hydroelectric | | Base-load | | 572 |
| | Mid-Atlantic | Darlington, MD | 11 |
| | Hydroelectric | Base-load | 572 |
| |
Criterion | Mid-Atlantic | Oakland, MD | 28 |
| | 51 |
| | Wind | | Base-load | | 36 |
| (f)(h) | Mid-Atlantic | Oakland, MD | 28 |
| 51 |
| Wind | Base-load | 36 |
| (e)(g) |
Fair Wind | Mid-Atlantic | Garrett County, MD | 12 |
| | | | Wind | | Base-load | | 30 |
| | |
Solar Maryland MC | Mid-Atlantic | Various, MD | 17 |
| | | | Solar | | Base-load | | 29 |
| | |
Fourmile | Mid-Atlantic | Garrett County, MD | 16 |
| | 51 |
| | Wind | | Base-load | | 20 |
| (f)(h) | |
Solar New Jersey 1 | Mid-Atlantic | Various, NJ | 5 |
| | | | Solar | | Base-load | | 18 |
| | |
Solar New Jersey 2 | Mid-Atlantic | Various, NJ | 2 |
| | | | Solar | | Base-load | | 11 |
| | |
|
| | | | | | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
Solar Horizons | Mid-Atlantic | Emmitsburg, MD | 1 |
| | 51 |
| | Solar | | Base-load | | 8 |
| (f)(h) |
Solar Maryland | Mid-Atlantic | Various, MD | 11 |
| | | | Solar | | Base-load | | 8 |
| |
Solar Maryland 2 | Mid-Atlantic | Various, MD | 3 |
| | | | Solar | | Base-load | | 8 |
| |
Solar Federal | Mid-Atlantic | Trenton, NJ | 1 |
| | | | Solar | | Base-load | | 5 |
| |
Solar New Jersey 3 | Mid-Atlantic | Middle Township, NJ | 5 |
| | 51 |
| | Solar | | Base-load | | 1 |
| (f)(h) |
Solar DC | Mid-Atlantic | District of Columbia | 1 |
| | | | Solar | | Base-load | | 1 |
| |
Muddy Run | Mid-Atlantic | Drumore, PA | 8 |
| | | | Hydroelectric | | Intermediate | | 1,070 |
| |
Eddystone 3, 4 | Mid-Atlantic | Eddystone, PA | 2 |
| | | | Oil/Gas | | Intermediate | | 760 |
| |
Perryman | Mid-Atlantic | Aberdeen, MD | 5 |
| | | | Oil/Gas | | Peaking | | 404 |
| |
Croydon | Mid-Atlantic | West Bristol, PA | 8 |
| | | | Oil | | Peaking | | 391 |
| |
Handsome Lake | Mid-Atlantic | Kennerdell, PA | 5 |
| | | | Gas | | Peaking | | 268 |
| |
Notch Cliff | Mid-Atlantic | Baltimore, MD | 8 |
| | | | Gas | | Peaking | | 117 |
| |
Westport | Mid-Atlantic | Baltimore, MD | 1 |
| | | | Gas | | Peaking | | 116 |
| |
Richmond | Mid-Atlantic | Philadelphia, PA | 2 |
| | | | Oil | | Peaking | | 98 |
| |
Gould Street | Mid-Atlantic | Baltimore, MD | 1 |
| | | | Gas | | Peaking | | 97 |
| |
Philadelphia Road | Mid-Atlantic | Baltimore, MD | 4 |
| | | | Oil | | Peaking | | 61 |
| |
Eddystone | Mid-Atlantic | Eddystone, PA | 4 |
| | | | Oil | | Peaking | | 60 |
| |
Fairless Hills | Mid-Atlantic | Fairless Hills, PA | 2 |
| | | | Landfill Gas | | Peaking | | 60 |
| |
Delaware | Mid-Atlantic | Philadelphia, PA | 4 |
| | | | Oil | | Peaking | | 56 |
| |
Southwark | Mid-Atlantic | Philadelphia, PA | 4 |
| | | | Oil | | Peaking | | 52 |
| |
Falls | Mid-Atlantic | Morrisville, PA | 3 |
| | | | Oil | | Peaking | | 51 |
| |
Moser | Mid-Atlantic | Lower PottsgroveTwp., PA | 3 |
| | | | Oil | | Peaking | | 51 |
| |
Riverside | Mid-Atlantic | Baltimore, MD | 2 |
| | | | Oil/Gas | | Peaking | | 39 |
| |
Chester | Mid-Atlantic | Chester, PA | 3 |
| | | | Oil | | Peaking | | 39 |
| |
Schuylkill | Mid-Atlantic | Philadelphia, PA | 2 |
| | | | Oil | | Peaking | | 30 |
| |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 1 |
| | 42.59 |
| | Oil | | Peaking | | 16 |
| (f) |
Pennsbury | Mid-Atlantic | Morrisville, PA | 2 |
| | | | Landfill Gas | | Peaking | | 6 |
| |
Total Mid-Atlantic | | | | | | | | | | | 11,566 |
| |
| | | | | | | | | | | | |
Whitetail | ERCOT | Webb County, TX | 57 |
| | 51 |
| | Wind | | Base-load | | 46 |
| (f)(h) |
Sendero | ERCOT | Jim Hogg and Zapata County, TX | 39 |
| | 51 |
| | Wind | | Base-load | | 40 |
| (f)(h) |
Colorado Bend II | ERCOT | Wharton, TX | 3 |
| | | | Gas | | Intermediate | | 1,088 |
| |
Wolf Hollow II | ERCOT | Granbury, TX | 3 |
| | | | Gas | | Intermediate | | 1,064 |
| |
Wolf Hollow 1, 2, 3 | ERCOT | Granbury, TX | 3 |
| | | | Gas | | Intermediate | | 705 |
| (l) |
Mountain Creek 8 | ERCOT | Dallas, TX | 1 |
| | | | Gas | | Intermediate | | 568 |
| (l) |
Colorado Bend | ERCOT | Wharton, TX | 6 |
| | | | Gas | | Intermediate | | 468 |
| (l) |
Handley 3 | ERCOT | Fort Worth, TX | 1 |
| | | | Gas | | Intermediate | | 395 |
| (l) |
Handley 4, 5 | ERCOT | Fort Worth, TX | 2 |
| | | | Gas | | Peaking | | 870 |
| (l) |
Mountain Creek 6, 7 | ERCOT | Dallas, TX | 2 |
| | | | Gas | | Peaking | | 240 |
| (l) |
LaPorte | ERCOT | Laporte, TX | 4 |
| | | | Gas | | Peaking | | 152 |
| (l) |
Total ERCOT | | | | | | | | | | | 5,636 |
| |
| | | | | | | | | | | | |
Solar Massachusetts | New England | Various, MA | 10 |
| | | | Solar | | Base-load | | 7 |
| |
Holyoke Solar | New England | Various, MA | 2 |
| | | | Solar | | Base-load | | 5 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Fair Wind | Mid-Atlantic | Garrett County, MD | 12 |
| | Wind | Base-load | 30 |
| |
Solar Maryland MC | Mid-Atlantic | Various, MD | 40 |
| | Solar | Base-load | 36 |
| |
Fourmile | Mid-Atlantic | Garrett County, MD | 16 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Solar New Jersey 1 | Mid-Atlantic | Various, NJ | 5 |
| | Solar | Base-load | 18 |
| |
Solar New Jersey 2 | Mid-Atlantic | Various, NJ | 2 |
| | Solar | Base-load | 11 |
| |
Solar Horizons | Mid-Atlantic | Emmitsburg, MD | 1 |
| 51 |
| Solar | Base-load | 8 |
| (e)(g) |
Solar Maryland | Mid-Atlantic | Various, MD | 11 |
| | Solar | Base-load | 8 |
| |
Solar Maryland 2 | Mid-Atlantic | Various, MD | 3 |
| | Solar | Base-load | 8 |
| |
Constellation New Energy | Mid-Atlantic | Gaithersburg, MD | 1 |
| | Solar | Base-load | 5 |
| |
Solar Federal | Mid-Atlantic | Trenton, NJ | 1 |
| | Solar | Base-load | 5 |
| |
Solar New Jersey 3 | Mid-Atlantic | Middle Township, NJ | 5 |
| 51 |
| Solar | Base-load | 1 |
| (e)(g) |
Solar DC | Mid-Atlantic | District of Columbia | 1 |
| | Solar | Base-load | 1 |
| |
Muddy Run | Mid-Atlantic | Drumore, PA | 8 |
| | Hydroelectric | Intermediate | 1,070 |
| |
Eddystone 3, 4 | Mid-Atlantic | Eddystone, PA | 2 |
| | Oil/Gas | Intermediate | 760 |
| |
Perryman | Mid-Atlantic | Aberdeen, MD | 5 |
| | Oil/Gas | Peaking | 404 |
| |
Croydon | Mid-Atlantic | West Bristol, PA | 8 |
| | Oil | Peaking | 391 |
| |
Handsome Lake | Mid-Atlantic | Kennerdell, PA | 5 |
| | Gas | Peaking | 268 |
| |
Notch Cliff | Mid-Atlantic | Baltimore, MD | 8 |
| | Gas | Peaking | 117 |
| (k) |
Westport | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 116 |
| (k) |
Richmond | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 98 |
| |
Gould Street | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 97 |
| (k) |
Philadelphia Road | Mid-Atlantic | Baltimore, MD | 4 |
| | Oil | Peaking | 61 |
| |
Eddystone | Mid-Atlantic | Eddystone, PA | 4 |
| | Oil | Peaking | 60 |
| |
Fairless Hills | Mid-Atlantic | Fairless Hills, PA | 2 |
| | Landfill Gas | Peaking | 60 |
| (k) |
Delaware | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 56 |
| |
|
| | | | | | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
Solar Net Metering | New England | Uxbridge, MA | 1 |
| | | | Solar | | Base-load | | 2 |
| |
Solar Connecticut | New England | Various, CT | 1 |
| | | | Solar | | Base-load | | 1 |
| |
Mystic 8, 9 | New England | Charlestown, MA | 6 |
| | | | Gas | | Intermediate | | 1,417 |
| |
Mystic 7 | New England | Charlestown, MA | 1 |
| | | | Oil/Gas | | Intermediate | | 575 |
| |
Wyman | New England | Yarmouth, ME | 1 |
| | 5.9 |
| | Oil | | Intermediate | | 36 |
| (f) |
West Medway | New England | West Medway, MA | 3 |
| | | | Oil | | Peaking | | 124 |
| |
Framingham | New England | Framingham, MA | 3 |
| | | | Oil | | Peaking | | 30 |
| |
Mystic Jet | New England | Charlestown, MA | 1 |
| | | | Oil | | Peaking | | 9 |
| |
Total New England | | | | | | | | | | | 2,206 |
| |
| | | | | | | | | | | | |
Nine Mile Point | New York | Scriba, NY | 2 |
| | 50.01 |
| | Uranium | | Base-load | | 838 |
| (f)(g) |
FitzPatrick | New York | Scriba, NY | 1 |
| | | | Uranium | | Base-load | | 842 |
| |
Ginna | New York | Ontario, NY | 1 |
| | 50.01 |
| | Uranium | | Base-load | | 288 |
| (f)(g) |
Solar New York | New York | Bethlehem, NY | 1 |
| | | | Solar | | Base-load | | 3 |
| |
Total New York | | | | | | | | | | | 1,971 |
| |
| | | | | | | | | | | | |
AVSR | Other | Lancaster, CA | 1 |
| | | | Solar | | Base-load | | 242 |
| |
Bluestem | Other | Beaver County, OK | 60 |
| | 51 |
| | Wind | | Base-load | | 101 |
| (f)(h)(i) |
Exelon Wind 4 | Other | Gruver, TX | 38 |
| | | | Wind | | Base-load | | 80 |
| |
Shooting Star | Other | Kiowa County, KS | 65 |
| | 51 |
| | Wind | | Base-load | | 53 |
| (f)(h) |
Albany Green Energy | Other | Albany, GA | 1 |
| | 99 |
| | Biomass | | Base-load | | 46 |
| (j) |
Solar Arizona | Other | Various, AZ | 127 |
| | | | Solar | | Base-load | | 46 |
| |
Bluegrass Ridge | Other | King City, MO | 27 |
| | 51 |
| | Wind | | Base-load | | 29 |
| (f)(h) |
California PV Energy 2 | Other | Various, CA | 89 |
| | | | Solar | | Base-load | | 27 |
| |
Conception | Other | Barnard, MO | 24 |
| | 51 |
| | Wind | | Base-load | | 26 |
| (f)(h) |
Cow Branch | Other | Rock Port, MO | 24 |
| | 51 |
| | Wind | | Base-load | | 26 |
| (f)(h) |
Solar Arizona 2 | Other | Various, AZ | 25 |
| | | | Solar | | Base-load | | 23 |
| |
California PV Energy | Other | Various, CA | 53 |
| | | | Solar | | Base-load | | 21 |
| |
Mountain Home | Other | Glenns Ferry, ID | 20 |
| | 51 |
| | Wind | | Base-load | | 21 |
| (f)(h) |
High Mesa | Other | Elmore Co., ID | 19 |
| | 51 |
| | Wind | | Base-load | | 20 |
| (f)(h) |
Echo 1 | Other | Echo, OR | 21 |
| | 50.49 |
| | Wind | | Base-load | | 17 |
| (f)(h) |
Sacramento PV Energy | Other | Sacramento, CA | 4 |
| | 51 |
| | Solar | | Base-load | | 15 |
| (f)(h) |
Cassia | Other | Buhl, ID | 14 |
| | 51 |
| | Wind | | Base-load | | 15 |
| (f)(h) |
Wildcat | Other | Lovington, NM | 13 |
| | 51 |
| | Wind | | Base-load | | 14 |
| (f)(h) |
Echo 2 | Other | Echo, OR | 10 |
| | 51 |
| | Wind | | Base-load | | 10 |
| (f)(h) |
Exelon Wind 5 | Other | Texhoma, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
Exelon Wind 6 | Other | Texhoma, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
Exelon Wind 7 | Other | Sunray, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
Exelon Wind 8 | Other | Sunray, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
Exelon Wind 9 | Other | Sunray, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
Exelon Wind 10 | Other | Dumas, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Southwark | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 52 |
| |
Falls | Mid-Atlantic | Morrisville, PA | 3 |
| | Oil | Peaking | 51 |
| |
Moser | Mid-Atlantic | Lower PottsgroveTwp., PA | 3 |
| | Oil | Peaking | 51 |
| |
Riverside | Mid-Atlantic | Baltimore, MD | 2 |
| | Oil | Peaking | 39 |
| (k)(l) |
Chester | Mid-Atlantic | Chester, PA | 3 |
| | Oil | Peaking | 39 |
| |
Schuylkill | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 30 |
| |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 1 |
| 42.59 |
| Oil | Peaking | 16 |
| (e) |
Pennsbury | Mid-Atlantic | Morrisville, PA | 2 |
| | Landfill Gas | Peaking | 4 |
| (e) |
Bethlehem | Mid-Atlantic | Bethlehem, PA | 1 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Eastern | Mid-Atlantic | Bethlehem, PA | 3 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Total Mid-Atlantic | | | | | | | 10,982 |
| |
| | | | | | | | |
Whitetail | ERCOT | Webb County, TX | 57 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Sendero | ERCOT | Jim Hogg and Zapata County, TX | 39 |
| 51 |
| Wind | Base-load | 40 |
| (e)(g) |
Constellation Solar Texas | Other | Various, TX | 11 |
| | Solar | Base-load | 13 |
| |
Colorado Bend II | ERCOT | Wharton, TX | 3 |
| | Gas | Intermediate | 1,088 |
| |
Wolf Hollow II | ERCOT | Granbury, TX | 3 |
| | Gas | Intermediate | 1,064 |
| |
Handley 3 | ERCOT | Fort Worth, TX | 1 |
| | Gas | Intermediate | 395 |
| |
Handley 4, 5 | ERCOT | Fort Worth, TX | 2 |
| | Gas | Peaking | 870 |
| |
Total ERCOT | | | | | | | 3,516 |
| |
| | | | | | | | |
Solar Massachusetts | New England | Various, MA | 10 |
| | Solar | Base-load | 7 |
| |
Holyoke Solar | New England | Various, MA | 2 |
| | Solar | Base-load | 5 |
| |
Solar Net Metering | New England | Uxbridge, MA | 1 |
| | Solar | Base-load | 2 |
| |
Solar Connecticut | New England | Various, CT | 1 |
| | Solar | Base-load | 1 |
| |
Mystic 8, 9 | New England | Charlestown, MA | 6 |
| | Gas | Intermediate | 1,417 |
| |
Mystic 7 | New England | Charlestown, MA | 1 |
| | Oil/Gas | Intermediate | 573 |
| (m) |
Wyman | New England | Yarmouth, ME | 1 |
| 5.9 |
| Oil | Intermediate | 35 |
| (e) |
West Medway | New England | West Medway, MA | 3 |
| | Oil | Peaking | 123 |
| |
|
| | | | | | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | | Percent Owned(b) | | Primary Fuel Type | | Primary Dispatch Type(c) | | Net Generation Capacity (MW)(d) | |
Exelon Wind 11 | Other | Dumas, TX | 8 |
| | | | Wind | | Base-load | | 10 |
| |
High Plains | Other | Panhandle, TX | 8 |
| | 99.5 |
| | Wind | | Base-load | | 10 |
| (f) |
Tuana Springs | Other | Hagerman, ID | 8 |
| | 51 |
| | Wind | | Base-load | | 9 |
| (f)(h) |
Solar Georgia | Other | Various, GA | 10 |
| | | | Solar | | Base-load | | 8 |
| |
Solar Georgia 2 | Other | Various, GA | 6 |
| | | | Solar | | Base-load | | 8 |
| |
Greensburg | Other | Greensburg, KS | 10 |
| | 51 |
| | Wind | | Base-load | | 7 |
| (f)(h) |
Outback Solar | Other | Christmas Valley, OR | 1 |
| | | | Solar | | Base-load | | 6 |
| |
Echo 3 | Other | Echo, OR | 6 |
| | 50.49 |
| | Wind | | Base-load | | 5 |
| (f)(h) |
Three Mile Canyon | Other | Boardman, OR | 6 |
| | 51 |
| | Wind | | Base-load | | 5 |
| (f)(h) |
Loess Hills | Other | Rock Port, MO | 4 |
| | | | Wind | | Base-load | | 5 |
| |
Mohave Sunrise Solar | Other | Fort Mohave, AZ | 1 |
| | | | Solar | | Base-load | | 5 |
| |
Denver Airport Solar | Other | Denver, CO | 1 |
| | 51 |
| | Solar | | Base-load | | 2 |
| (f)(h) |
Hillabee | Other | Alexander City, AL | 3 |
| | | | Gas | | Intermediate | | 753 |
| |
Grande Prairie | Other | Alberta, Canada | 1 |
| | | | Gas | | Peaking | | 105 |
| |
SEGS 4, 5, 6 | Other | Boron, CA | 3 |
| | 4.2-12.2 |
| | Solar | | Peaking | | 9 |
| (f) |
Total Other | | | | | | | | | | | 1,839 |
| |
Total | | | | | | | | | | | 35,168 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Framingham | New England | Framingham, MA | 3 |
| | Oil | Peaking | 31 |
| |
Mystic Jet | New England | Charlestown, MA | 1 |
| | Oil | Peaking | 9 |
| (m) |
Total New England | | | | | | | 2,203 |
| |
| | | | | | | | |
Nine Mile Point | New York | Scriba, NY | 2 |
| 50.01 |
| Uranium | Base-load | 838 |
| (e)(f) |
FitzPatrick | New York | Scriba, NY | 1 |
| | Uranium | Base-load | 842 |
| |
Ginna | New York | Ontario, NY | 1 |
| 50.01 |
| Uranium | Base-load | 288 |
| (e)(f) |
Solar New York | New York | Bethlehem, NY | 1 |
| | Solar | Base-load | 3 |
| |
Total New York | | | | | | | 1,971 |
| |
| | | | | | | | |
Antelope Valley | Other | Lancaster, CA | 1 |
| | Solar | Base-load | 242 |
| |
Bluestem | Other | Beaver County, OK | 60 |
| 51 |
| Wind | Base-load | 101 |
| (e)(g)(h) |
Exelon Wind 4 | Other | Gruver, TX | 38 |
| | Wind | Base-load | 80 |
| |
Shooting Star | Other | Kiowa County, KS | 65 |
| 51 |
| Wind | Base-load | 53 |
| (e)(g) |
Albany Green Energy | Other | Albany, GA | 1 |
| 99 |
| Biomass | Base-load | 52 |
| (i) |
Solar Arizona | Other | Various, AZ | 127 |
| | Solar | Base-load | 46 |
| |
Bluegrass Ridge | Other | King City, MO | 27 |
| 51 |
| Wind | Base-load | 29 |
| (e)(g) |
California PV Energy 2 | Other | Various, CA | 89 |
| | Solar | Base-load | 27 |
| |
Conception | Other | Barnard, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Cow Branch | Other | Rock Port, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Solar Arizona 2 | Other | Various, AZ | 25 |
| | Solar | Base-load | 23 |
| |
California PV Energy | Other | Various, CA | 53 |
| | Solar | Base-load | 21 |
| |
Mountain Home | Other | Glenns Ferry, ID | 20 |
| 51 |
| Wind | Base-load | 21 |
| (e)(g) |
High Mesa | Other | Elmore Co., ID | 19 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Echo 1 | Other | Echo, OR | 21 |
| 50.49 |
| Wind | Base-load | 17 |
| (e)(g) |
Sacramento PV Energy | Other | Sacramento, CA | 4 |
| 51 |
| Solar | Base-load | 15 |
| (e)(g) |
Cassia | Other | Buhl, ID | 14 |
| 51 |
| Wind | Base-load | 15 |
| (e)(g) |
Wildcat | Other | Lovington, NM | 13 |
| 51 |
| Wind | Base-load | 14 |
| (e)(g) |
Echo 2 | Other | Echo, OR | 10 |
| 51 |
| Wind | Base-load | 10 |
| (e)(g) |
Exelon Wind 5 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 6 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 7 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 8 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 9 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 10 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 11 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
High Plains | Other | Panhandle, TX | 8 |
| 99.5 |
| Wind | Base-load | 10 |
| (e) |
Solar Georgia 2 | Other | Various, GA | 8 |
| | Solar | Base-load | 10 |
| |
Tuana Springs | Other | Hagerman, ID | 8 |
| 51 |
| Wind | Base-load | 9 |
| (e)(g) |
Solar Georgia | Other | Various, GA | 10 |
| | Solar | Base-load | 8 |
| |
Greensburg | Other | Greensburg, KS | 10 |
| 51 |
| Wind | Base-load | 7 |
| (e)(g) |
Outback Solar | Other | Christmas Valley, OR | 1 |
| | Solar | Base-load | 6 |
| |
Echo 3 | Other | Echo, OR | 6 |
| 50.49 |
| Wind | Base-load | 5 |
| (e)(g) |
Three Mile Canyon | Other | Boardman, OR | 6 |
| 51 |
| Wind | Base-load | 5 |
| (e)(g) |
Loess Hills | Other | Rock Port, MO | 4 |
| | Wind | Base-load | 5 |
| |
California PV Energy 3 | Other | Various, CA | 10 |
| | Solar | Base-load | 5 |
| |
Mohave Sunrise Solar | Other | Fort Mohave, AZ | 1 |
| | Solar | Base-load | 5 |
| |
Denver Airport Solar | Other | Denver, CO | 1 |
| 51 |
| Solar | Base-load | 2 |
| (e)(g) |
Hillabee | Other | Alexander City, AL | 3 |
| | Gas | Intermediate | 753 |
| |
Grande Prairie | Other | Alberta, Canada | 1 |
| | Gas | Peaking | 105 |
| |
SEGS 4, 5, 6 | Other | Boron, CA | 3 |
| 4.2-12.2 |
| Solar | Peaking | 9 |
| (e) |
Total Other | | | | | | | 1,852 |
| |
Total | | | | | | | 32,463 |
| |
__________
| |
(a) | All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors. |
| |
(b) | 100%, unless otherwise indicated. |
| |
(c) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. |
| |
(d) | For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity. |
| |
(e) | Generation had previously agreed to permanently cease generation operations at Oyster Creek by the end of 2019. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. See Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information regarding the early retirement of Oyster Creek. |
| |
(f) | Net generation capacity is stated at proportionate ownership share. |
| |
(g)(f) | Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2. |
| |
(h)(g) | Reflects the sale of 49% of ExGen Renewables PartnersEGRP to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(i)(h) | ExGen Renewables PartnersEGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. |
| |
(j)(i) | Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity. |
| |
(k)(j) | Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information regardinginformation. |
| |
(k) | Generation has agreed to retire and cease generation operations at the early retirement of TMI.Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit 8), Westport and Pennsbury units on or before June 1, 2020. |
| |
(l) | As a result ofGeneration plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019. |
| |
(m) | Generation plans to retire and cease generation operation at the EGTP bankruptcyMystic 7 and deconsolidationMystic Jet units on November 7, 2017, Generation deconsolidated EGTP's assets and liabilities from Generation's consolidated financial statements. As of December 31, 2017, these assets were still under Generation's ownership and included in the table. See Note 4 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.or about June 1, 2022. |
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding
nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin Generation’s consolidated financial condition or results of operations.
ComEd
ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ComEd’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows:
| | Voltage (Volts) | Circuit Miles | | Circuit Miles |
765,000 | 90 | | 90 |
345,000 | 2,718 | | 2,716 |
138,000 | 2,209 | | 2,209 |
ComEd’s electric distribution system includes 35,38335,398 circuit miles of overhead lines and 31,79832,010 circuit miles of underground lines.
First Mortgage and Insurance
The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First Mortgage Bonds are issued.
ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of ComEd.
PECO
PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows:
| | Voltage (Volts) | Circuit Miles | | Circuit Miles | |
500,000 | 188(a) | | 188 | (a) |
230,000 | 548 | | 549 | |
138,000 | 135 | | 135 | |
69,000 | 181 | | 181 | |
__________
| |
(a) | In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey. |
PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,3229,367 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2017:2018:
|
| | |
| Pipeline Miles |
Transmission | 309 |
|
Distribution | 6,8896,912 |
|
Service piping | 6,3286,377 |
|
Total | 13,24713,298 |
|
PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 157160 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 3130 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.
First Mortgage and Insurance
The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.
PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of PECO.
BGE
BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and
licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows:
| | Voltage (Volts) | Circuit Miles | | Circuit Miles |
500,000 | 218 | | 218 |
230,000 | 352 | | 358 |
138,000 | 55 | | 55 |
115,000 | 713 | | 706 |
BGE’s electric distribution system includes 9,1699,191 circuit miles of overhead lines and 17,20917,295 circuit miles of underground lines.
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2017:2018:
|
| | |
| Pipeline Miles |
Transmission | 161 |
|
Distribution | 7,3067,348 |
|
Service piping | 6,2636,305 |
|
Total | 13,73013,814 |
|
BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,056 mmcf and a send-out capacity of 332 mmcf/day and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.
Property Insurance
BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of BGE.
Pepco
Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 142 |
230,000 | | 767 |
138,000 | | 61 |
115,000 | | 38 |
Pepco’s electric distribution system includes approximately 4,1054,127 circuit miles of overhead lines and 6,8447,039 circuit miles of underground lines. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.
First Mortgage and Insurance
The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First Mortgage Bonds are issued.
Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of Pepco.
DPL
DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
DPL’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows: | | Voltage (Volts) | Circuit Miles | | Circuit Miles |
500,000 | 16 | | 16 |
230,000 | 470 | | 471 |
138,000 | 557 | | 586 |
69,000 | 576 | | 569 |
DPL’s electric distribution system includes approximately 6,0286,031 circuit miles of overhead lines and 6,1036,298 circuit miles of underground lines. DPL also owns and operates a distribution system control center in New Castle, Delaware.
Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2017:2018:
|
| | |
| Pipeline Miles |
Transmission (a) | 8 |
|
Distribution | 2,0612,065 |
|
Service piping | 1,3931,398 |
|
Total | 3,4623,471 |
|
___________
| |
(a) | DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities. |
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 3,045250 mmcf and an emergency sendout capability of 36,000 Mcf per 36 mmcf/day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 158,485 Mcf per 158 mmcf/day.
First Mortgage and Insurance
The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First Mortgage Bonds are issued.
DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of DPL.
ACE
ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ACE’s high voltage electric transmission lines owned and in service at December 31, 20172018 were as follows:
| | Voltage (Volts) | Circuit Miles | | Circuit Miles |
500,000 | 281 | | — |
230,000 | 237 | | 221 |
138,000 | 268 | | 239 |
69,000 | 652 | | 663 |
ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,9002,927 circuit miles of underground lines. ACE also owns and operates a distribution system control center in Mays Landing, New Jersey.
First Mortgage and Insurance
The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First Mortgage Bonds are issued.
ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect onin the consolidated financial condition or results of operations of ACE.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 34 — Regulatory Matters and Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
|
| |
ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share data, unless otherwise noted)
|
| |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the New York Stock Exchange.Exchange (trading symbol: EXC). As of January 31, 2018,2019, there were 965,029,399969,745,933 shares of common stock outstanding and approximately 104,90999,857 record holders of common stock.
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
High price | $ | 42.67 |
| | $ | 38.78 |
| | $ | 37.44 |
| | $ | 37.19 |
| | $ | 36.36 |
| | $ | 37.70 |
| | $ | 36.37 |
| | $ | 35.95 |
|
Low price | 37.55 |
| | 35.37 |
| | 33.30 |
| | 34.47 |
| | 29.82 |
| | 32.86 |
| | 33.18 |
| | 26.26 |
|
Close | 39.41 |
| | 37.67 |
| | 36.07 |
| | 35.98 |
| | 35.49 |
| | 33.29 |
| | 36.36 |
| | 35.86 |
|
Dividends | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.318 |
| | 0.318 |
| | 0.318 |
| | 0.310 |
|
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 20132014 through 2017.2018.
This performance chart assumes:
$100 invested on December 31, 20122013 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and
All dividends are reinvested.
| | Value of Investment at December 31, | | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | 2013 | 2014 | 2015 | 2016 | 2017 | 2018 |
Exelon Corporation | $100 | $65.11 | $88.14 | $66.01 | $84.36 | $132.16 | $100 | $140.61 | $109.44 | $145.34 | $167.22 | $197.86 |
S&P 500 | $100 | $144.74 | $161.22 | $160.05 | $175.31 | $182.82 | $100 | $113.68 | $115.24 | $129.02 | $157.17 | $150.27 |
S&P Utilities | $100 | $107.43 | $133.52 | $122.32 | $137.24 | $147.82 | $100 | $128.98 | $122.73 | $142.72 | $160.00 | $166.57 |
Generation
As of January 31, 2018,2019, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2018,2019, there were 127,021,256127,021,331 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2018,2019, in addition to Exelon, there were 294 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2018,2019, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2018,2019, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2018,2019, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2018,2019, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2018,2019, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2018,2019, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.
The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment
periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to certain dividend restrictions established by the MDPSC. First, in connection with the Constellation merger,MDPSC that prohibit BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days beforeNo such a dividend is paid and notify the MDPSC that BGE's equity ratio is at least 48% within five business days after dividend payment.event has occurred.
Pepco is subject to certain dividend restrictions limits imposed by: (i) state corporate laws, which impose limitationsestablished by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the funds that candividend payment, Pepco's equity ratio would be used to pay dividends,48% as equity levels are calculated under the ratemaking precedents of the MDPSC and (ii)DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities.three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions imposed by: (i) state corporate laws, which impose limitationsestablished by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the funds that candividend payment, DPL's equity ratio would be used to pay dividends,48% as equity levels are calculated under the ratemaking precedents of the DPSC and (ii)MDPSC or (b) DPL’s
senior unsecured credit rating is rated by one of the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and any other restrictions imposed in connection with the incurrence of liabilities.three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions imposed by: (i) state corporate laws,established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which impose limitations on the funds that can be usedrequires ACE to pay dividends and the regulatory requirement that ACE obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%; (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders. Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends.. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
At December 31, 2017,2018, Exelon had retained earnings of $13,503$14,766 million, including Generation’s undistributed earnings of $4,310$3,724 million, ComEd’s retained earnings of $1,132$1,337 million consisting of retained earnings appropriated for future dividends of $2,771$2,976 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,087$1,242 million, BGE’s retained earnings of $1,536$1,640 million, and PHI's undistributed earnings of $(10)$62 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 20172018 and 2016:2017:
| | | 2017 | | 2016 | 2018 | | 2017 |
(per share) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
Exelon | $ | 0.328 |
| | $ | 0.328 |
| | $ | 0.328 |
| | $ | 0.328 |
| | $ | 0.318 |
| | $ | 0.318 |
| | $ | 0.318 |
| | $ | 0.310 |
| 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
|
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's quarterly common dividend payments:
| | | 2017 | | 2016 | 2018 | | 2017 |
(in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter |
Generation | $ | 165 |
| | $ | 164 |
| | $ | 166 |
| | $ | 164 |
| | $ | 755 |
| | $ | 56 |
| | $ | 56 |
| | $ | 55 |
| $ | 313 |
| | $ | 311 |
| | $ | 189 |
| | $ | 188 |
| | $ | 165 |
| | $ | 164 |
| | $ | 166 |
| | $ | 164 |
|
ComEd | 106 |
| | 105 |
| | 106 |
| | 105 |
| | 94 |
| | 92 |
| | 92 |
| | 91 |
| 114 |
| | 116 |
| | 115 |
| | 114 |
| | 106 |
| | 105 |
| | 106 |
| | 105 |
|
PECO | 72 |
| | 72 |
| | 72 |
| | 72 |
| | 69 |
| | 69 |
| | 70 |
| | 69 |
| 6 |
| | 7 |
| | 6 |
| | 287 |
| | 72 |
| | 72 |
| | 72 |
| | 72 |
|
BGE | 50 |
| | 49 |
| | 50 |
| | 49 |
| | 45 |
| | 44 |
| | 45 |
| | 45 |
| 52 |
| | 52 |
| | 53 |
| | 52 |
| | 50 |
| | 49 |
| | 50 |
| | 49 |
|
PHI | 44 |
| | 136 |
| | 62 |
| | 69 |
| | 99 |
| | 50 |
| | 16 |
| | 108 |
| 94 |
| | 123 |
| | 38 |
| | 71 |
| | 44 |
| | 136 |
| | 62 |
| | 69 |
|
Pepco | — |
| | 75 |
| | 28 |
| | 30 |
| | 44 |
| | 37 |
| | 16 |
| | 39 |
| 41 |
| | 78 |
| | 25 |
| | 25 |
| | — |
| | 75 |
| | 28 |
| | 30 |
|
DPL | 30 |
| | 28 |
| | 24 |
| | 30 |
| | 15 |
| | 1 |
| | — |
| | 38 |
| 38 |
| | 18 |
| | 4 |
| | 36 |
| | 30 |
| | 28 |
| | 24 |
| | 30 |
|
ACE | 15 |
| | 31 |
| | 12 |
| | 10 |
| | 39 |
| | 13 |
| | — |
| | 11 |
| 13 |
| | 27 |
| | 10 |
| | 9 |
| | 15 |
| | 31 |
| | 12 |
| | 10 |
|
First Quarter 20182019 Dividend
On January 30, 2018,February 5, 2019, the Exelon Board of Directors declared a first quarter 20182019 regular quarterly dividend of $0.3450$0.3625 per share on Exelon’s common stock payable on March 9, 2018,8, 2019, to shareholders of record of Exelon at the end of the day on February 15, 2018.20, 2019.
|
| |
ITEM 6. | SELECTED FINANCIAL DATA |
Exelon
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions, except per share data) | 2017 | | 2016(a) | | 2015 | | 2014(b) | | 2013 | 2018 | | 2017(c, d) | | 2016(a, c, d) | | 2015(c) | | 2014(b,c) |
Statement of Operations data: | | | | | | | | | | | | | | | | | | |
Operating revenues | $ | 33,531 |
| | $ | 31,360 |
| | $ | 29,447 |
| | $ | 27,429 |
| | $ | 24,888 |
| $ | 35,985 |
| | $ | 33,565 |
| | $ | 31,366 |
| | $ | 29,447 |
| | $ | 27,429 |
|
Operating income | 4,260 |
| | 3,112 |
| | 4,409 |
| | 3,096 |
| | 3,669 |
| 3,898 |
| | 4,395 |
| | 3,212 |
| | 4,554 |
| | 3,210 |
|
Net income | 3,849 |
|
| 1,204 |
|
| 2,250 |
|
| 1,820 |
|
| 1,729 |
| 2,084 |
|
| 3,876 |
|
| 1,196 |
|
| 2,250 |
|
| 1,820 |
|
Net income attributable to common shareholders | 3,770 |
| | 1,134 |
| | 2,269 |
| | 1,623 |
| | 1,719 |
| 2,010 |
| | 3,786 |
| | 1,121 |
| | 2,269 |
| | 1,623 |
|
Earnings per average common share (diluted): | | | | | | | | | | | | | | | | | | |
Net income | $ | 3.97 |
| | $ | 1.22 |
| | $ | 2.54 |
| | $ | 1.88 |
| | $ | 2.00 |
| $ | 2.07 |
| | $ | 3.99 |
| | $ | 1.21 |
| | $ | 2.54 |
| | $ | 1.88 |
|
Dividends per common share | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| | $ | 1.24 |
| | $ | 1.46 |
| $ | 1.38 |
| | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| | $ | 1.24 |
|
__________
| |
(a) | The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016. |
| |
(b) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(c) | Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(d) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017(a) | | 2016(a) | | 2015(a) | | 2014(a) |
Balance Sheet data: | | | | | | | | | | | | | | | | | | |
Current assets | $ | 11,834 |
| | $ | 12,412 |
| | $ | 15,334 |
| | $ | 11,853 |
| | $ | 9,562 |
| $ | 13,360 |
| | $ | 11,896 |
| | $ | 12,451 |
| | $ | 15,334 |
| | $ | 11,853 |
|
Property, plant and equipment, net | 74,202 |
| | 71,555 |
| | 57,439 |
| | 52,170 |
| | 47,330 |
| 76,707 |
| | 74,202 |
| | 71,555 |
| | 57,439 |
| | 52,170 |
|
Total assets | 116,700 |
|
| 114,904 |
|
| 95,384 |
|
| 86,416 |
|
| 79,243 |
| 119,666 |
|
| 116,770 |
|
| 114,952 |
|
| 95,384 |
|
| 86,416 |
|
Current liabilities | 10,796 |
| | 13,457 |
| | 9,118 |
| | 8,762 |
| | 7,686 |
| 11,404 |
| | 10,798 |
| | 13,463 |
| | 9,118 |
| | 8,762 |
|
Long-term debt, including long-term debt to financing trusts | 32,565 |
| | 32,216 |
| | 24,286 |
| | 19,853 |
| | 18,165 |
| 34,465 |
| | 32,565 |
| | 32,216 |
| | 24,286 |
| | 19,853 |
|
Shareholders’ equity | 29,857 |
| | 25,837 |
| | 25,793 |
| | 22,608 |
| | 22,732 |
| 30,764 |
| | 29,896 |
| | 25,860 |
| | 25,793 |
| | 22,608 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014(a) | | 2013 | 2018 | | 2017(b) | | 2016(b) | | 2015 | | 2014(a) |
Statement of Operations data: | | | | | | | | | | | | | | | | | | |
Operating revenues | $ | 18,466 |
| | $ | 17,751 |
| | $ | 19,135 |
| | $ | 17,393 |
| | $ | 15,360 |
| $ | 20,437 |
| | $ | 18,500 |
| | $ | 17,757 |
| | $ | 19,135 |
| | $ | 17,393 |
|
Operating income | 921 |
| | 836 |
| | 2,275 |
| | 1,176 |
| | 1,677 |
| 975 |
| | 947 |
| | 820 |
| | 2,275 |
| | 1,176 |
|
Net income | 2,771 |
| | 558 |
| | 1,340 |
| | 1,019 |
| | 1,060 |
| 443 |
| | 2,798 |
| | 550 |
| | 1,340 |
| | 1,019 |
|
__________
| |
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(b) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017(a) | | 2016(a) | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | | | | | | | | | | |
Current assets | $ | 6,820 |
| | $ | 6,528 |
| | $ | 6,342 |
| | $ | 7,311 |
| | $ | 5,964 |
| $ | 8,433 |
| | $ | 6,882 |
| | $ | 6,567 |
| | $ | 6,342 |
| | $ | 7,311 |
|
Property, plant and equipment, net | 24,906 |
| | 25,585 |
| | 25,843 |
| | 23,028 |
| | 20,111 |
| 23,981 |
| | 24,906 |
| | 25,585 |
| | 25,843 |
| | 23,028 |
|
Total assets | 48,387 |
|
| 46,974 |
|
| 46,529 |
|
| 44,951 |
|
| 40,700 |
| 47,556 |
|
| 48,457 |
|
| 47,022 |
|
| 46,529 |
|
| 44,951 |
|
Current liabilities | 4,189 |
| | 5,683 |
| | 4,933 |
| | 4,459 |
| | 3,842 |
| 5,769 |
| | 4,191 |
| | 5,689 |
| | 4,933 |
| | 4,459 |
|
Long-term debt, including long-term debt to affiliate | 8,644 |
| | 8,124 |
| | 8,869 |
| | 7,582 |
| | 7,111 |
| |
Long-term debt, including long-term debt to affiliates | | 7,887 |
| | 8,644 |
| | 8,124 |
| | 8,869 |
| | 7,582 |
|
Member’s equity | 13,630 |
| | 11,482 |
| | 11,635 |
| | 12,718 |
| | 12,725 |
| 13,204 |
| | 13,669 |
| | 11,505 |
| | 11,635 |
| | 12,718 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
ComEd
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | | | | | | | | | | |
Operating revenues | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| | $ | 4,564 |
| | $ | 4,464 |
| $ | 5,882 |
| | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| | $ | 4,564 |
|
Operating income | 1,323 |
| | 1,205 |
| | 1,017 |
| | 980 |
| | 954 |
| 1,146 |
| | 1,323 |
| | 1,205 |
| | 1,017 |
| | 980 |
|
Net income | 567 |
| | 378 |
| | 426 |
| | 408 |
| | 249 |
| 664 |
| | 567 |
| | 378 |
| | 426 |
| | 408 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | | | | | | | | | | |
Current assets | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| | $ | 1,723 |
| | $ | 1,540 |
| $ | 1,570 |
| | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| | $ | 1,723 |
|
Property, plant and equipment, net | 20,723 |
| | 19,335 |
| | 17,502 |
| | 15,793 |
| | 14,666 |
| 22,058 |
| | 20,723 |
| | 19,335 |
| | 17,502 |
| | 15,793 |
|
Total assets | 29,726 |
|
| 28,335 |
|
| 26,532 |
|
| 25,358 |
|
| 24,089 |
| 31,213 |
|
| 29,726 |
|
| 28,335 |
|
| 26,532 |
|
| 25,358 |
|
Current liabilities | 2,294 |
| | 2,938 |
| | 2,766 |
| | 1,923 |
| | 2,032 |
| 1,925 |
| | 2,294 |
| | 2,938 |
| | 2,766 |
| | 1,923 |
|
Long-term debt, including long-term debt to financing trusts | 6,966 |
| | 6,813 |
| | 6,049 |
| | 5,870 |
| | 5,235 |
| 8,006 |
| | 6,966 |
| | 6,813 |
| | 6,049 |
| | 5,870 |
|
Shareholders’ equity | 9,542 |
| | 8,725 |
| | 8,243 |
| | 7,907 |
| | 7,528 |
| 10,247 |
| | 9,542 |
| | 8,725 |
| | 8,243 |
| | 7,907 |
|
PECO
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | | | | | | | | | | |
Operating revenues | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| | $ | 3,094 |
| | $ | 3,100 |
| $ | 3,038 |
| | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| | $ | 3,094 |
|
Operating income | 655 |
| | 702 |
| | 630 |
| | 572 |
| | 666 |
| 587 |
| | 655 |
| | 702 |
| | 630 |
| | 572 |
|
Net income | 434 |
| | 438 |
| | 378 |
| | 352 |
| | 395 |
| 460 |
| | 434 |
| | 438 |
| | 378 |
| | 352 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | | | | | | | | | | |
Current assets | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| | $ | 645 |
| | $ | 821 |
| $ | 782 |
| | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| | $ | 645 |
|
Property, plant and equipment, net | 8,053 |
| | 7,565 |
| | 7,141 |
| | 6,801 |
| | 6,384 |
| 8,610 |
| | 8,053 |
| | 7,565 |
| | 7,141 |
| | 6,801 |
|
Total assets | 10,170 |
|
| 10,831 |
|
| 10,367 |
|
| 9,860 |
|
| 9,521 |
| 10,642 |
|
| 10,170 |
|
| 10,831 |
|
| 10,367 |
|
| 9,860 |
|
Current liabilities | 1,267 |
| | 727 |
| | 944 |
| | 653 |
| | 889 |
| 809 |
| | 1,267 |
| | 727 |
| | 944 |
| | 653 |
|
Long-term debt, including long-term debt to financing trusts | 2,587 |
| | 2,764 |
| | 2,464 |
| | 2,416 |
| | 2,120 |
| 3,268 |
| | 2,587 |
| | 2,764 |
| | 2,464 |
| | 2,416 |
|
Shareholder's equity | 3,577 |
| | 3,415 |
| | 3,236 |
| | 3,121 |
| | 3,065 |
| 3,820 |
| | 3,577 |
| | 3,415 |
| | 3,236 |
| | 3,121 |
|
BGE
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | | | | | | | | | | |
Operating revenues | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| | $ | 3,165 |
| | $ | 3,065 |
| $ | 3,169 |
| | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| | $ | 3,165 |
|
Operating income | 614 |
| | 550 |
| | 558 |
| | 439 |
| | 449 |
| 474 |
| | 614 |
| | 550 |
| | 558 |
| | 439 |
|
Net income | 307 |
| | 294 |
| | 288 |
| | 211 |
| | 210 |
| 313 |
| | 307 |
| | 294 |
| | 288 |
| | 211 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | | 2013 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | | | | | | | | | | |
Current assets | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| | $ | 951 |
| | $ | 1,009 |
| $ | 786 |
| | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| | $ | 951 |
|
Property, plant and equipment, net | 7,602 |
| | 7,040 |
| | 6,597 |
| | 6,204 |
| | 5,864 |
| 8,243 |
| | 7,602 |
| | 7,040 |
| | 6,597 |
| | 6,204 |
|
Total assets | 9,104 |
|
| 8,704 |
|
| 8,295 |
|
| 8,056 |
|
| 7,839 |
| 9,716 |
|
| 9,104 |
|
| 8,704 |
|
| 8,295 |
|
| 8,056 |
|
Current liabilities | 760 |
| | 707 |
| | 1,134 |
| | 794 |
| | 800 |
| 774 |
| | 760 |
| | 707 |
| | 1,134 |
| | 794 |
|
Long-term debt, including long-term debt to financing trusts and variable interest entities | 2,577 |
| | 2,533 |
| | 1,732 |
| | 2,109 |
| | 2,179 |
| |
Long-term debt, including long-term debt to financing trusts | | 2,876 |
| | 2,577 |
| | 2,533 |
| | 1,732 |
| | 2,109 |
|
Shareholder's equity | 3,141 |
| | 2,848 |
| | 2,687 |
| | 2,563 |
| | 2,365 |
| 3,354 |
| | 3,141 |
| | 2,848 |
| | 2,687 |
| | 2,563 |
|
PHI
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | Successor | | | Predecessor | Successor | | | Predecessor |
| For the Year Ended December 31, | | March 24 to December 31 | | | January 1 to March 23, | | For the Years Ended December 31, | For the Years Ended December 31, | | March 24 to December 31 | | | January 1 to March 23, | | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | | 2016 | | 2015 | | 2014 | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | Statement of Operations data(a): | | | | | | | | | | Statement of Operations data(a): | | | | | | | | | | | |
Operating revenues | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $ | 4,935 |
| | $ | 4,808 |
| $ | 4,805 |
| | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $4,935 | | $ | 4,808 |
|
Operating income | 769 |
| | 93 |
| | | 105 |
| | 673 |
| | 605 |
| 650 |
| | 769 |
| | 93 |
| | | 105 |
| | 673 |
| | 605 |
|
Net income (loss) from continuing operations | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| | 242 |
| 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| | 242 |
|
Net income (loss) | 362 |
| | (61 | ) | | | 19 |
| | 327 |
| | 242 |
| 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 327 |
| | 242 |
|
| | | | | | | | | | Successor | | | Predecessor |
| Successor | | | Predecessor | December 31, | | | December 31, |
(In millions) | December 31, 2017 | | December 31, 2016 | | | December 31, 2015 | 2018 | | 2017 | | 2016 | | | 2015 |
Balance Sheet data(a): | | | | | | | | | | | | | | |
Current assets | $ | 1,551 |
| | $ | 1,838 |
| | | $ | 1,474 |
| $ | 1,533 |
| | $ | 1,551 |
| | $ | 1,838 |
| | | $ | 1,474 |
|
Property, plant and equipment, net | 12,498 |
| | 11,598 |
| | | 10,864 |
| 13,446 |
| | 12,498 |
| | 11,598 |
| | | 10,864 |
|
Total assets | 21,247 |
| | 21,025 |
| | | 16,188 |
| 21,984 |
| | 21,247 |
| | 21,025 |
| | | 16,188 |
|
Current liabilities | 1,931 |
| | 2,284 |
| | | 2,327 |
| 1,592 |
| | 1,931 |
| | 2,284 |
| | | 2,327 |
|
Long-term debt | 5,478 |
| | 5,645 |
| | | 4,823 |
| 6,134 |
| | 5,478 |
| | 5,645 |
| | | 4,823 |
|
Preferred Stock | — |
| | — |
| | | 183 |
| — |
| | — |
| | — |
| | | 183 |
|
Member’s equity/Shareholders' equity | 8,825 |
| | 8,016 |
| | | 4,413 |
| 9,282 |
| | 8,825 |
| | 8,016 |
| | | 4,413 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above. |
Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | | | | | | |
Operating revenues | $ | 2,158 |
| | $ | 2,186 |
| | $ | 2,129 |
| | $ | 2,055 |
| $ | 2,239 |
| | $ | 2,158 |
| | $ | 2,186 |
| | $ | 2,129 |
| | $ | 2,055 |
|
Operating income | 399 |
| | 174 |
| | 385 |
| | 349 |
| 320 |
| | 399 |
| | 174 |
| | 385 |
| | 349 |
|
Net income | 205 |
| | 42 |
| | 187 |
| | 171 |
| 210 |
| | 205 |
| | 42 |
| | 187 |
| | 171 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | | | | | | |
Current assets | $ | 710 |
| | $ | 684 |
| | $ | 726 |
| $ | 760 |
| | $ | 710 |
| | $ | 684 |
| | $ | 726 |
|
Property, plant and equipment, net | 6,001 |
| | 5,571 |
| | 5,162 |
| 6,460 |
| | 6,001 |
| | 5,571 |
| | 5,162 |
|
Total assets | 7,832 |
| | 7,335 |
| | 6,908 |
| 8,299 |
| | 7,832 |
| | 7,335 |
| | 6,908 |
|
Current liabilities | 550 |
| | 596 |
| | 455 |
| 628 |
| | 550 |
| | 596 |
| | 455 |
|
Long-term debt | 2,521 |
| | 2,333 |
| | 2,340 |
| 2,704 |
| | 2,521 |
| | 2,333 |
| | 2,340 |
|
Shareholders’ equity | 2,533 |
| | 2,300 |
| | 2,240 |
| |
Shareholder's equity | | 2,740 |
| | 2,533 |
| | 2,300 |
| | 2,240 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above. |
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | | | | | | |
Operating revenues | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| | $ | 1,282 |
| $ | 1,332 |
| | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| | $ | 1,282 |
|
Operating income | 229 |
| | 50 |
| | 165 |
| | 207 |
| 190 |
| | 229 |
| | 50 |
| | 165 |
| | 207 |
|
Net income (loss) | 121 |
| | (9 | ) | | 76 |
| | 104 |
| 120 |
| | 121 |
| | (9 | ) | | 76 |
| | 104 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | | | | | | |
Current assets | $ | 325 |
| | $ | 370 |
| | $ | 388 |
| $ | 336 |
| | $ | 325 |
| | $ | 370 |
| | $ | 388 |
|
Property, plant and equipment, net | 3,579 |
| | 3,273 |
| | 3,070 |
| 3,821 |
| | 3,579 |
| | 3,273 |
| | 3,070 |
|
Total assets | 4,357 |
| | 4,153 |
| | 3,969 |
| 4,588 |
| | 4,357 |
| | 4,153 |
| | 3,969 |
|
Current liabilities | 547 |
| | 381 |
| | 564 |
| 375 |
| | 547 |
| | 381 |
| | 564 |
|
Long-term debt | 1,217 |
| | 1,221 |
| | 1,061 |
| 1,403 |
| | 1,217 |
| | 1,221 |
| | 1,061 |
|
Shareholders’ equity | 1,335 |
| | 1,326 |
| | 1,237 |
| |
Shareholder's equity | | 1,509 |
| | 1,335 |
| | 1,326 |
| | 1,237 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above. |
ACE
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | | 2014 | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | | | | | | |
Operating revenues | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| | $ | 1,210 |
| $ | 1,236 |
| | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| | $ | 1,210 |
|
Operating income | 157 |
| | 7 |
| | 134 |
| | 137 |
| 149 |
| | 157 |
| | 7 |
| | 134 |
| | 137 |
|
Net income (loss) | 77 |
| | (42 | ) | | 40 |
| | 46 |
| 75 |
| | 77 |
| | (42 | ) | | 40 |
| | 46 |
|
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | | | | | | |
Current assets | $ | 258 |
| | $ | 399 |
| | $ | 546 |
| $ | 240 |
| | $ | 258 |
| | $ | 399 |
| | $ | 546 |
|
Property, plant and equipment, net | 2,706 |
| | 2,521 |
| | 2,322 |
| 2,966 |
| | 2,706 |
| | 2,521 |
| | 2,322 |
|
Total assets | 3,445 |
| | 3,457 |
| | 3,387 |
| 3,699 |
| | 3,445 |
| | 3,457 |
| | $ | 3,387 |
|
Current liabilities | 619 |
| | 320 |
| | 297 |
| 422 |
| | 619 |
| | 320 |
| | $ | 297 |
|
Long-term debt | 840 |
| | 1,120 |
| | 1,153 |
| 1,170 |
| | 840 |
| | 1,120 |
| | 1,153 |
|
Shareholders’ equity | 1,043 |
| | 1,034 |
| | 1,000 |
| |
Shareholder's equity | | 1,126 |
| | 1,043 |
| | 1,034 |
| | 1,000 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above. |
|
| |
Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon 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, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services in northern Illinois, including the City of Chicago.
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 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 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 engaged in the generation, delivery, and a wholly owned subsidiarymarketing of Exelon.energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has twelve reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions in Generation)Regions), ComEd, PECO, BGE, Pepco, DPL and PHI's three utilityACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments (Pepco, DPLconsisting of Mid-Atlantic, Midwest, New York, ERCOT and ACE).Other Power Regions. See Note 251 - Significant Accounting Policies and Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Through its business services subsidiary, BSC, Exelon provides its operating subsidiaries with a variety of corporate governance support services at cost, including corporate strategy and development, legal, human resources, financial, information technology finance, real estate, security, corporate communications and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost.cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of these servicesBSC and PHISCO are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service agreements. subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
PHISCO, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, finance, 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 PHISCO 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.
Financial Results of Operations
GAAP Results of Operations
Operations. The following table sets forth Exelon's GAAP consolidated results of operationsNet Income attributable to common shareholders by Registrant for the year ended December 31, 2018 compared to the same period in 2017 and December 31, 2017 compared to the same period in 2016. 2016 amounts includeFor additional information regarding the operations of PHI, Pepco, DPL and ACE from March 24, 2016 throughfinancial results for the years ended December 31, 2016. All amounts presented below are before2018, 2017 and 2016 see the impactdiscussions of income taxes, except as noted.Results of Operations by Registrant.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Favorable (Unfavorable) Variance |
| 2017 | | 2016 | |
| Generation | | ComEd | | PECO | | BGE | | PHI | | Other | | Exelon | | Exelon(b) | |
Operating revenues | $ | 18,466 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | (1,196 | ) | | $ | 33,531 |
| | $ | 31,360 |
| | $ | 2,171 |
|
Purchased power and fuel expense | 9,690 |
| | 1,641 |
| | 969 |
| | 1,133 |
| | 1,716 |
| | (1,114 | ) | | 14,035 |
| | 12,640 |
| | (1,395 | ) |
Revenue net of purchased power and fuel expense(a) | 8,776 |
| | 3,895 |
| | 1,901 |
| | 2,043 |
| | 2,963 |
| | (82 | ) | | 19,496 |
| | 18,720 |
| | 776 |
|
Other operating expenses | | | | | | | | | | | | | | | | | |
Operating and maintenance | 6,291 |
| | 1,427 |
| | 806 |
| | 716 |
| | 1,068 |
| | (182 | ) | | 10,126 |
| | 10,048 |
| | (78 | ) |
Depreciation and amortization | 1,457 |
| | 850 |
| | 286 |
| | 473 |
| | 675 |
| | 87 |
| | 3,828 |
| | 3,936 |
| | 108 |
|
Taxes other than income | 555 |
| | 296 |
| | 154 |
| | 240 |
| | 452 |
| | 34 |
| | 1,731 |
| | 1,576 |
| | (155 | ) |
Total other operating expenses | 8,303 |
| | 2,573 |
| | 1,246 |
| | 1,429 |
| | 2,195 |
| | (61 | ) | | 15,685 |
| | 15,560 |
| | (125 | ) |
Gain (Loss) on sales of assets | 2 |
| | 1 |
| | — |
| | — |
| | 1 |
| | (1 | ) | | 3 |
| | (48 | ) | | 51 |
|
Bargain purchase gain | 233 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 233 |
| | — |
| | 233 |
|
Gain on deconsolidation of business | 213 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 213 |
| | — |
| | 213 |
|
Operating income (loss) | 921 |
| | 1,323 |
| | 655 |
| | 614 |
| | 769 |
| | (22 | ) | | 4,260 |
| | 3,112 |
| | 1,148 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | |
Interest expense, net | (440 | ) | | (361 | ) | | (126 | ) | | (105 | ) | | (245 | ) | | (283 | ) | | (1,560 | ) | | (1,536 | ) | | (24 | ) |
Other, net | 948 |
| | 22 |
| | 9 |
| | 16 |
| | 54 |
| | 7 |
| | 1,056 |
| | 413 |
| | 643 |
|
Total other income and (deductions) | 508 |
| | (339 | ) | | (117 | ) | | (89 | ) | | (191 | ) | | (276 | ) | | (504 | ) | | (1,123 | ) | | 619 |
|
Income (loss) before income taxes | 1,429 |
| | 984 |
| | 538 |
| | 525 |
| | 578 |
| | (298 | ) | | 3,756 |
| | 1,989 |
| | 1,767 |
|
Income taxes | (1,375 | ) | | 417 |
| | 104 |
| | 218 |
| | 217 |
| | 294 |
| | (125 | ) | | 761 |
| | 886 |
|
Equity in (losses) earnings of unconsolidated affiliates | (33 | ) | | — |
| | — |
| | — |
| | 1 |
| | — |
| | (32 | ) | | (24 | ) | | (8 | ) |
Net income (loss) | 2,771 |
| | 567 |
| | 434 |
| | 307 |
| | 362 |
| | (592 | ) | | 3,849 |
| | 1,204 |
| | 2,645 |
|
Net income attributable to noncontrolling interests and preference stock dividends | 77 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 79 |
| | 70 |
| | (9 | ) |
Net income (loss) attributable to common shareholders | $ | 2,694 |
| | $ | 567 |
| | $ | 434 |
| | $ | 307 |
| | $ | 362 |
| | $ | (594 | ) | | $ | 3,770 |
| | $ | 1,134 |
| | $ | 2,636 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Exelon | $ | 2,010 |
| | $ | 3,786 |
| | $ | (1,776 | ) | | $ | 1,121 |
| | $ | 2,665 |
|
Generation | 370 |
| | 2,710 |
| | (2,340 | ) | | 483 |
| | 2,227 |
|
ComEd | 664 |
| | 567 |
| | 97 |
| | 378 |
| | 189 |
|
PECO | 460 |
| | 434 |
| | 26 |
| | 438 |
| | (4 | ) |
BGE | 313 |
| | 307 |
| | 6 |
| | 286 |
| | 21 |
|
Pepco | 210 |
| | 205 |
| | 5 |
| | 42 |
| | 163 |
|
DPL | 120 |
| | 121 |
| | (1 | ) | | (9 | ) | | 130 |
|
ACE | 75 |
| | 77 |
| | (2 | ) | | (42 | ) | | 119 |
|
Other(b) | (195 | ) | | (594 | ) | | 399 |
| | (422 | ) | | (172 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to March 23, |
| 2018 | | 2017 | | | 2016 | | | 2016 |
PHI(a) | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
__________
| |
(a) | The Registrants’ evaluate operating performance usingIncludes the measureconsolidated results of revenues net of purchased powerPepco, DPL and fuel expense. The Registrant's believe that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues 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.ACE. |
| |
(b) | As a result of the PHI Merger, ExelonPrimarily includes the consolidated results of PHI, Pepco, DPLeliminating and ACE from March 24, 2016 through December 31, 2016.consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities. |
Exelon’sYear Ended December 31, 2018 Compared to Year Ended December 31, 2017. Net income attributable to common shareholders was $3,770decreased by $1,776 million for the year ended December 31, 2017 as compared to $1,134 million for the year ended December 31, 2016, and diluted earnings per average common share were $3.97 fordecreased to $2.07 in 2018 from $3.99 in 2017 primarily due to:
Impacts associated with the year ended December 31,one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to $1.22 for the year ended December 31, 2016.net gains in 2017;
Revenue net of purchased powerLower realized energy prices;
Accelerated depreciation and fuel expense, which is a non-GAAP measure discussed below, increased by $776 million as compared to 2016. The year-over-year increase was primarilyamortization due to the following favorable factors:decision to early retire the Oyster Creek and TMI nuclear facilities;
Increase of $104 million at BGE primarily dueThe gain associated with the FitzPatrick acquisition in 2017;
Decrease in reserves for uncertain tax positions in 2017 related to the impactsdeductibility of certain merger commitments associated with the electric2012 Constellation and natural gas distribution rate orders issued by2016 PHI acquisitions;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the MDPSCfourth quarter of 2017;
Long-lived asset impairments of certain merchant wind assets in June 2016West Texas; and July 2016
Increased storm costs at PECO and an increase in transmission formula rate revenues;BGE.
Increase of $99 million at ComEd primarily due to increased electric distribution and transmission formula rate revenues (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE),The decreases were partially offset by lower revenues resulting from the change to defer and recover over time energy efficiency costs pursuant to FEJA and the impact of favorable weather conditions in 2016; and
Increase of $767 million in Revenue net of purchased power and fuel due to the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016, as well as distribution rate increases effective in 2016 and 2017.by;
The year-over-year increase in Revenue net of purchased power and fuel expense was partially offset by the following unfavorable factors:
Decrease of $134 million at Generation due to mark-to-market losses of $175 million in 2017 compared to mark-to-market losses of $41 million in 2016;
Decrease of $46 million at PECO primarily due to unfavorable weather conditions; and
Decrease of $11 million at Generation primarily due to lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation's natural gas portfolio, partially offset by the impact of the New York CES, increased nuclear volumesand Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the acquisitionTCJA at Generation;
Net realized gains on NDT funds;
The gain on the settlement of FitzPatrick, higher capacity prices, the additiona long-term gas supply agreement;
Decreased nuclear outage days;
Increased electric distribution and energy efficiency formula rate earnings at ComEd;
Regulatory rate increases at PECO, BGE and PHI;
The impact of two combined-cycle gas turbinesfavorable weather at PECO, DPL and ACE; and
The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The decrease in Texas and lower nuclear fuel prices.
Operating and maintenance expense increased by $78 million as compared to 2016. The year-over-year increasediluted earnings per share was primarilyalso due to the following unfavorable factors:increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
IncreaseYear Ended December 31, 2017 Compared to Year Ended December 31, 2016. Net income attributable to common shareholdersincreased by $2,665 million and diluted earnings per average common share increased to $3.99 in 2017 from $1.21 in 2016 primarily due to:
Impacts associated with the one-time remeasurement of $307 million at Generationdeferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to higher asset impairment charges;
Increase of $127 million at Generation primarily due to Generation’sthe decision in 2017 to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;
Increase of $104 million at Generation due to increased nuclear refueling outage costs;Higher net unrealized and realized gains on NDT funds;
Increase of $84 million at Generation due to the annual updateThe impact of the GenerationNew York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices;
Decreased nuclear decommissioning obligationoutage days;
Decrease in reserves for uncertain tax positions in 2017 related to the non-regulatory unitsdeductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment in 2017 versus 2016;
Increased electric distribution and transmission formula rate earnings at ComEd;
Regulatory rate increases at BGE and PHI; and
IncreasePenalties and associated interest expense as a result of $253 million at PHI duea tax court decision on Exelon's like-kind exchange position in 2016.
The increases were partially offset by;
Long-lived asset impairments primarily related to the inclusionEGTP assets held for sale;
Lower realized energy prices;
The conclusion of PHI's results for the year ended December 31, 2017 comparedGinna Reliability Support Services Agreement;
Increased costs related to the period March 24, 2016 to December 31, 2016.acquisition of the FitzPatrick nuclear facility;
Increased mark-to-market losses;
The year-over-yearimpact of unfavorable weather at ComEd, PECO, DPL and ACE; and
The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The net increase in Operating and maintenance expensediluted earnings per share from the items listed above was partially offset by the following favorable factors:
Decrease of $665 million at Exelon due to merger commitment and other merger-related costs of $73 million in 2017 compared to $738 million in 2016;
Decrease of $85 million at ComEd due to the change to defer and recover over time energy efficiency costs pursuant to the Illinois Future Energy Jobs Act; and
Decrease of $21 million at BGE primarily due to certain disallowances contained in the June and July 2016 rate orders, partially offset by the impact of the favorable 2016 settlement of the Baltimore City conduit fee dispute.
Depreciation and amortization expense decreased by $108 million primarily due to lower accelerated depreciation and amortization expenseincrease in Exelon’s average diluted shares outstanding as a result of the June 2017 decision to early retire the TMI nuclear facility compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities, partially offset by increased depreciation expense as a result of ongoing capital expenditures across all operating companies and the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016.common stock issuance.
Taxes other than income increased by $155 million primarily due to increased real estate taxes and sales and use taxes at Generation, as well as the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016.
Gain (Loss) on sales of assets increased by $51 million primarily due to certain Generation projects and contracts being terminated or renegotiated in 2016, partially offset by a gain associated with Generation’s sale of the retired New Boston generating site in 2016.
Bargain purchase gain increased by $233 million due to the gain associated with Generation's acquisition of FitzPatrick in 2017.
Gain on deconsolidation of business increased by $213 million due to the deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing.
Interest expense, net increased by $24 million primarily due to the inclusion of PHI's results for the year ended December 31, 2017 compared to the period March 24, 2016 to December 31, 2016, partially offset by additional interest related to Exelon's like-kind exchange tax position recorded in 2016 compared to 2017.
Other, net increased by $643 million primarily due to higher net unrealized and realized gains on NDT funds at Generation for the year ended December 31, 2017 as compared to the same period in 2016 and the penalty recorded in 2016 related to Exelon's like-kind exchange tax position.
Exelon’s effective income tax rates for the years ended December 31, 2017 and 2016 were (3.3)% and 38.3%, respectively. Exelon's effective income tax rate for the year ended December 31, 2017 includes the impact of the Tax Cuts and Jobs Act. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
For further detail regarding the financial results for the years ended December 31, 2017 and 2016, including explanation of the non-GAAP measure revenues net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
Adjusted (non-GAAP) Operating Earnings
Exelon’s Adjusted (non-GAAP) operating earnings for the year ended December 31, 2017 were $2,471 million, or $2.60 per diluted share, compared with Adjusted (non-GAAP) operating earnings of $2,488 million, or $2.68 per diluted share, for the same period in 2016. Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 20172018 as compared to 2017 and 2016:
|
| | | | | | | | | | | | | | | |
| For the years ended December 31, |
| 2017 | | 2016 |
(All amounts after tax; in millions, except per share amounts) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 3,770 |
| | $ | 3.97 |
| | $ | 1,134 |
| | $ | 1.22 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $68 and $18, respectively) | 107 |
| | 0.11 |
| | 24 |
| | 0.03 |
|
Unrealized Gains Related to NDT Fund Investments(b) (net of taxes of $204 and $77, respectively) | (318 | ) | | (0.34 | ) | | (118 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $22 and $22, respectively) | 34 |
| | 0.04 |
| | 35 |
| | 0.04 |
|
Merger and Integration Costs(d) (net of taxes of $25 and $50, respectively) | 40 |
| | 0.04 |
| | 114 |
| | 0.12 |
|
Merger Commitments(e) (net of taxes of $137 and $126, respectively) | (137 | ) | | (0.14 | ) | | 437 |
| | 0.47 |
|
Long-Lived Asset Impairments(f) (net of taxes of $204 and $68, respectively) | 321 |
| | 0.34 |
| | 103 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $134 and $273, respectively) | 207 |
| | 0.22 |
| | 432 |
| | 0.47 |
|
Reassessment of Deferred Income Taxes(h) (entire amount represents tax expense) | (1,299 | ) | | (1.37 | ) | | 10 |
| | 0.01 |
|
Cost Management Program(i) (net of taxes of $21 and $21, respectively) | 34 |
| | 0.04 |
| | 34 |
| | 0.04 |
|
Like-Kind Exchange Tax Position(j) (net of taxes of $66 and $61, respectively) | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Asset Retirement Obligation(k) (net of taxes of $1 and $13, respectively) | (2 | ) | | — |
| | (75 | ) | | (0.08 | ) |
Tax Settlements(l) (net of taxes of $1 and $0, respectively) | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Bargain Purchase Gain(m) (net of taxes of $0 and $0, respectively) | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Gain on Deconsolidation of Business(n) (net of taxes of $83 and $0, respectively) | (130 | ) | | (0.14 | ) | | — |
| | — |
|
Vacation Policy Change(o) (net of taxes of $21 and $0, respectively) | (33 | ) | | (0.03 | ) | | — |
| | — |
|
Curtailment of Generation Growth and Development Activities(p) (net of taxes of $0 and $35, respectively) | — |
| | — |
| | 57 |
| | 0.06 |
|
Change in Environmental Remediation Liabilities (net of taxes of $17 and $0, respectively) | 27 |
| | 0.03 |
| | — |
| | — |
|
Noncontrolling Interests(q) (net of taxes of $24 and $9, respectively) | 114 |
| | 0.12 |
| | 102 |
| | 0.11 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 2,471 |
| | $ | 2.60 |
| | $ | 2,488 |
| | $ | 2.68 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
(All amounts after tax; in millions, except per share amounts) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 2,010 |
| | $ | 2.07 |
| | $ | 3,786 |
| | $ | 3.99 |
| | $ | 1,121 |
| | $ | 1.21 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $89, $68 and $18, respectively) | 252 |
| | 0.26 |
| | 107 |
| | 0.11 |
| | 24 |
| | 0.03 |
|
Unrealized Losses (Gains) Related to NDT Funds(b) (net of taxes of $289, $286 and $112, respectively) | 337 |
| | 0.35 |
| | (318 | ) | | (0.34 | ) | | (118 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0, $22 and $22, respectively) | — |
| | — |
| | 34 |
| | 0.04 |
| | 35 |
| | 0.04 |
|
Merger and Integration Costs(d) (net of taxes of $2, $25 and $50, respectively) | 3 |
| | — |
| | 40 |
| | 0.04 |
| | 114 |
| | 0.12 |
|
Merger Commitments(e) (net of taxes of $0, $137 and $126, respectively) | — |
| | — |
| | (137 | ) | | (0.14 | ) | | 437 |
| | 0.47 |
|
Long-Lived Asset Impairments(f) (net of taxes of $13, $204 and $68, respectively) | 35 |
| | 0.04 |
| | 321 |
| | 0.34 |
| | 103 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $181, $134 and $273, respectively) | 512 |
| | 0.53 |
| | 207 |
| | 0.22 |
| | 432 |
| | 0.47 |
|
Cost Management Program(h) (net of taxes of $16, $21 and $21, respectively) | 48 |
| | 0.05 |
| | 34 |
| | 0.04 |
| | 34 |
| | 0.04 |
|
Annual Asset Retirement Obligation Update(i) (net of taxes of $7, $1 and $13, respectively) | 20 |
| | 0.02 |
| | (2 | ) | | — |
| | (75 | ) | | (0.08 | ) |
Vacation Policy Change(j) (net of taxes of $0, $21 and $0, respectively) | — |
| | — |
| | (33 | ) | | (0.03 | ) | | — |
| | — |
|
Change in Environmental Liabilities (net of taxes of $0, $17 and $0, respectively) | (1 | ) | | — |
| | 27 |
| | 0.03 |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0, $0 and $0, respectively) | — |
| | — |
| | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Gain on Deconsolidation of Business(l) (net of taxes of $0, $83 and $0, respectively) | — |
| | — |
| | (130 | ) | | (0.14 | ) | | — |
| | — |
|
Gain on Contract Settlement(m) (net of taxes of $20, $0 and $0, respectively) | (55 | ) | | (0.06 | ) | | — |
| | — |
| | — |
| | — |
|
Like-Kind Exchange Tax Position(n) (net of taxes of $0, $66 and $61, respectively) | — |
| | — |
| | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Curtailment of Generation Growth and Development Activities(o) (net of taxes of $0, $0 and $35, respectively) | — |
| | — |
| | — |
| | — |
| | 57 |
| | 0.06 |
|
Reassessment of Deferred Income Taxes(p) (entire amount represents tax expense) | (22 | ) | | (0.02 | ) | | (1,299 | ) | | (1.37 | ) | | 10 |
| | 0.01 |
|
Tax Settlements(q) (net of taxes of $0, $1 and $0, respectively) | — |
| | — |
| | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Noncontrolling Interests(r) (net of taxes of $24, $24 and $9, respectively) | (113 | ) | | (0.12 | ) | | 114 |
| | 0.12 |
| | 102 |
| | 0.11 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 3,026 |
| | $ | 3.12 |
| | $ | 2,487 |
| | $ | 2.62 |
| | $ | 2,475 |
| | $ | 2.67 |
|
__________
| |
(a) | Reflects the impact of net gains and losses on Generation’s economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s hedging activities. |
| |
(b) | Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund investments. |
| |
(c) | Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2017, the ConEdison Solutions and FitzPatrick acquisitions, and in 2016, the Integrys and ConEdison Solutions acquisitions. |
| |
(d) | Primarily reflects certain costs incurred for the PHI acquisition in 2017 and 2016 and Generation's FitzPatrick acquisition in 2017, including professional fees, employee-related expenses and integration activities. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to merger and acquisition costs. |
| |
(e) | Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2017, a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions, and in 2016, a charge related to a 2012 CEG merger commitment. See Note 4 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail related to PHI Merger commitments. |
| |
(f) | Primarily reflects charges to earnings in 2017 related to impairments of EGTP assets and the PHI District of Columbia sponsorship intangible asset, and in 2016, impairments of Upstream assets and certain wind projects at Generation. |
| |
(g) | Primarily reflects in 2017 accelerated depreciation and amortization expenses, increases to materials and supplies inventory reserves, construction work in progress impairments and charges for severance reserves associated with Generation’s decision to early retire the Three Mile Island nuclear facility. Primarily reflects in 2016 accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. |
| |
(h) | Reflects in 2017 one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the Tax Cuts and Jobs Act (including impacts on pension obligations), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment, and in 2016, the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. |
| |
(i) | Represents severance and reorganization costs related to a cost management program. |
| |
(j) | Represents in 2017 adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position, and in 2016, the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position. |
| |
(k) | Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. |
| |
(l) | Reflects benefits related to the favorable settlement in 2017 of certain income tax positions related to PHI's unregulated business interests that were transferred to Generation. |
| |
(m) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
| |
(n) | Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. |
| |
(o) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(p) | Reflects the the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(q) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT fund investments at CENG. |
Note:
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT fund investments,funds, the marginal statutory income tax rates for 2018, 2017 and 2016 ranged from 3926.0 percent to 41 percent.29.0 percent, 39.0 percent to 41.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund investment returns are taxed at differingdifferent rates for investments if they are in qualified vs.or non-qualified funds. The effective tax rates applied tofor the unrealized gains and losses related to NDT Fund investmentsfunds were 46.2 percent, 47.4 percent and 48.7 percent for the years ended December 31, 2018, 2017 and 2016, respectively.
Merger, Integration and Acquisition Costs
As a result of the PHI Merger that was completed on March 23, 2016, the Registrants have 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. In addition, as a result of the acquisition of the FitzPatrick nuclear generating station on March 31, 2017, Exelon and Generation incurred costs associated with evaluating, structuring and executing the transaction and integrating FitzPatrick 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 |
| For the Year Ended December 31, 2016 | | March 24, 2016 to December 31, 2016 |
| Exelon | | Generation | | Pepco | | DPL | | ACE | | PHI |
Merger commitments (a) | $ | 513 |
| | $ | 3 |
| | $ | 126 |
| | $ | 86 |
| | $ | 111 |
| | $ | 323 |
|
Changes in accounting and tax related policies and estimates | — |
| | — |
| | 25 |
| | 15 |
| | 5 |
| | — |
|
Total | $ | 513 |
| | $ | 3 |
| | $ | 151 |
| | $ | 101 |
| | $ | 116 |
| | $ | 323 |
|
__________
| |
(a) | Reflects the impact of net losses on economic hedging activities. See Note 4 —12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information related to hedging activities. |
| |
(b) | Reflects the impact of net unrealized gains and losses on Generation’s NDT funds for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact. |
| |
(c) | Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions. |
| |
(d) | Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for moreadditional information. |
In addition to the one-time PHI Merger charges discussed above, for the years ended December 31, 2017 and 2016, expense has been recognized for the PHI Merger and Generation's FitzPatrick acquisition as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-tax Expense |
| For the Year Ended December 31, 2017 |
Merger, Integration and Acquisition Expense: | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) |
Transaction(b) | $ | 6 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | — |
|
Other(c)(d) | 67 |
| | 75 |
| | 1 |
| | 4 |
| | 4 |
| | (18 | ) | | (6 | ) | | (7 | ) | | (6 | ) |
Total | $ | 73 |
| | $ | 80 |
| | $ | 1 |
| | $ | 4 |
| | $ | 4 |
| | $ | (18 | ) | | $ | (6 | ) | | $ | (7 | ) | | $ | (6 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pre-tax Expense |
| For the Year Ended December 31, 2016 |
Merger Integration and Acquisition Expense: | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) |
Transaction(b) | $ | 34 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Employee-related(e) | 77 |
| | 10 |
| | 2 |
| | 1 |
| | 1 |
| | 64 |
| | 30 |
| | 18 |
| | 15 |
|
Other(c)(d) | 52 |
| | 44 |
| | (8 | ) | | 4 |
| | (2 | ) | | 5 |
| | (2 | ) | | 2 |
| | 4 |
|
Total | $ | 163 |
| | $ | 56 |
| | $ | (6 | ) | | $ | 5 |
| | $ | (1 | ) | | $ | 69 |
| | $ | 28 |
| | $ | 20 |
| | $ | 19 |
|
__________
| |
(a) | For Exelon, Generation, PHI, Pepco, DPL and ACE, includes the operations of the acquired businesses beginning on March 24, 2016. |
| |
(b) | 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. |
| |
(c) | Costs to integrate PHI processes and systems into Exelon. For the year ended December 31, 2017, also includes costs to integrate FitzPatrick processes and systems into Exelon. |
| |
(d) | For the year ended December 31, 2017, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $24 million, $8 million, $8 million, and $8 million incurred at PHI, Pepco, DPL, and ACE, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $8 million, $6 million, $11 million, and $4 million incurred at ComEd, BGE, Pepco, and DPL, respectively, that have been recorded as a regulatory asset for anticipated recovery. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisition of $16 million incurred at PHI that have been recorded as a regulatory asset for anticipated recovery. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information.
|
| |
(e) | CostsRepresents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, primarily a decrease in reserves for employeeuncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions. |
| |
(f) | In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation. |
| |
(g) | In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. |
| |
(h) | Primarily represents severance and reorganization costs related to a cost management program. |
| |
(i) | For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property. |
| |
(j) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(k) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
| |
(l) | Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. |
| |
(m) | Represents the gain on the settlement of a long-term gas supply agreement at Generation. |
| |
(n) | Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position. |
| |
(o) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(p) | Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and OPEB expenseDistrict of Columbia statutory tax rates and retention bonuses.changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment. |
| |
(q) | Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests. |
| |
(r) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG. |
Significant 20172018 Transactions and Recent Developments
CorporateRegulatory Implications of the Tax Reform
On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) creating a 30% limitation on deductible interest expense (not applicable to regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production activities deduction; (5) eliminating the corporate alternative minimum taxCuts and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017.Jobs Act (TCJA)
The most significant change that impacts the Registrants is the reduction of the corporate federal income tax rate from 35% to 21% beginning January 1, 2018. Adjusted non-GAAP operating earnings per share for Exelon is expected to increase by approximately $0.10 on a run-rate basis in 2019 relative to Exelon’s projections before the TCJA. For the Utility Registrants have made filings with their respective State regulators to begin passing back to customers the amount and timing of when certain incomeongoing annual tax benefitssavings resulting from the TCJA are provided to customers may vary from jurisdiction to jurisdiction.
Beginning in 2018, Generation will incur lower income tax expense, which will decrease its projected effective income tax rate, even with the elimination of the domestic production activities deduction, and increase its net income. Generation’s operating cash inflows are also expected to increase beginning in 2018 reflecting the lower income tax rates and full expensing of capital investments. Generation’s projected effective income tax rate in 2018, 2019, and 2020 is expected to be approximately 22%.
Beginning in 2018, the Utility Registrants will incur lower income tax expense, which will generally decrease their projected effective income tax rates. The TCJA is expected to lead to lower customer rates over time due to lower income tax expense recoveries and the settlement of deferred income tax net regulatory liabilities. The TCJA is expected to lead to an incremental increase in rate base of approximately $1.7 billion by 2020 relative to previous expectations across the Utility Registrants. The increased rate base will be funded consistent with each utility jurisdiction, using a combination of third party debt financings and equity funding from Exelon generally consistent with existing capitalization ratio structures. To fund any additional equity contributions to the Utility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the increased operating cash flows at Generation referenced above, which over time are expected to exceed the incremental equity needs at the Utility Registrants. The TCJA is generally expected to result in lower operating cash inflows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates.
Exelon Corporate expects that the interest on its debt will continue to be fully tax deductible albeit at a lower tax rate.
The Utility Registrants continue to work with their state regulatory commissions to determine the amount and timing of the passing back of TCJA income tax savings benefits to customers; with filings either made, or expected to be made, at Pepco, DPL and ACE, and approved filings at ComEd and BGE.TCJA. The amounts being passed back or proposed to be passed back to customers reflect the annual benefit of lower income tax expense beginning January 1, 2018 (Feb. 1, 2018 for DPL Delaware),rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. To date, neither the PAPUC nor FERC has yet issued guidance on how and whenThe Utility Registrants have identified over $675 million in ongoing annual savings to reflect the impacts of thebe returned to customers related to TCJA in customer rates. Refer tofrom their distribution utility operations. See Note 3 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on their filings.other regulatory proceedings.
Early Nuclear Plant Retirements
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year and will not receive capacity revenue for that period, the third consecutive year that TMI failed to clear the PJM base residual capacity auction. The plant is currently committed to operate through May 2019. In 2017, as a result of the plant retirement decision of TMI, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $77 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 TMI 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. During the year ended December 31, 2017, both Exelon’s and Generation’s results include an incremental $262 million of pre-tax expense for these items.
The following table summarizes the estimated annual amount and timing of expected incremental non-cash expense items through 2019.Completed Utility Distribution Base Rate Case Proceedings
|
| | | | | | | | | | | | |
| | Actual | | Projected(a) |
Income statement expense (pre-tax) | | 2017 | | 2018 | | 2019 |
Depreciation and Amortization | | | | | | |
Accelerated depreciation(b) | | $ | 250 |
| | $ | 440 |
| | $ | 330 |
|
Accelerated nuclear fuel amortization | | 12 |
| | 20 |
| | 5 |
|
Total | | $ | 262 |
| | $ | 460 |
| | $ | 335 |
|
_________
| |
(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
| |
(b) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant costs associated with the construction of cooling towers to meet the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster Creek in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018 that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018.
Because of the decision to retire Oyster Creek in 2018, Exelon and Generation will recognize certain one-time charges in the first quarter of 2018 ranging from an estimated $25 million to $35 million (pre-tax) related to a materials and supplies inventory reserve adjustment, employee-related costs, and construction work-in-progress impairment, among other items. Estimated cash expenditures related to the one-time charges primarily for employee-related costs are expected to range from $5 million to $10 million.
In addition to these one-time charges, there will be financial impacts stemming from shortening the expected economic useful life of Oyster Creek primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. The following table summarizes the estimated amount of expected incremental non-cash expense items expected to be incurred in 2018 because of the early retirement decision.
|
| | |
| | Projected(b)
|
Income statement expense (pre-tax) | | 2018 |
Depreciation and Amortization | | |
Accelerated depreciation(a)
| | $110 to $140 |
Accelerated nuclear fuel amortization | | $40 |
Operating and Maintenance | | |
Increased ARO accretion | | Up to $5 |
|
| | | | | | | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
Pepco - District of Columbia (Electric) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
DPL - Maryland (Electric) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the accelerated depreciation of plant assets includingannual ongoing TCJA tax savings further discussed above. |
Pending Distribution Base Rate Case Proceedings
|
| | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | | Requested ROE | Expected Approval Timing |
ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019 |
Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
|
| | | | | | | | | | | | | | |
Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase) | | Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) | | 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
Pepco | 6 |
| 2 |
| 8 |
| | 7.82 | % | 10.50 | % |
DPL | 14 |
| 13 |
| 27 |
| | 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
| | 8.02 | % | 10.50 | % |
__________
| |
(a) | The time period for any ARC.challenges to the annual transmission formula rate update flings expired with no challenges submitted. |
| |
(b) | Actual results may differ basedThe initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and equity return on incremental future capital additions, actual unitstransmission rate bases. |
| |
(e) | As part of productionthe FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for nuclear fuel amortization, future revised ARO assumptions, etc.being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
EGTP Consent Agreement and BankruptcyPECO Transmission Formula Rate
On May 2,1, 2017, EGTP,PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an indirect subsidiaryOrder accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of Exelon and Generation, entered intothis proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate revenue decrease of $6 million. The revenue decrease of $6 million included
an orderly sales process to sell the assets of its wholly owned subsidiaries. Asapproximately $20 million reduction as a result Exelon and Generation classified certain EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss during 2017. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements and recorded a $213 million pre-tax gain. See Note 4 — Mergers, Acquisitions and Dispositions, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 13 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information regarding EGTP and the associated nonrecourse debt.
Acquisition of James A. FitzPatrick Nuclear Generating Station
On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station for a total purchase price of $289 million. In accounting for the acquisition as a business combination, Exelon and Generation recorded an after-tax bargain purchase gain of $233 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.
Illinois Future Energy Jobs Act
On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA was effective on June 1, 2017, and includes, among other provisions, (1) a Zero Emission Standard (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 MWhtax 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 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 3— Regulatory Matters of the Combined NotesTCJA. The updated transmission rate was effective June 1, 2018, subject to the Consolidated Financial Statements for additional information regarding FEJA. See Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information regarding the economic challenges facing Generation's Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.refund.
Illinois ZEC Procurement
OnPursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and will beginbegan recognizing revenue. Winning bidders will be entitled torevenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. InDuring the first quarter ofyear ended December 31, 2018, Generation will recognize approximately $150recognized revenue of $373 million, of revenue and ComEd will record an obligation to Generation and corresponding reduction to its regulatory liability of approximately $100which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
DismissalEarly Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of Litigation Challenging ZEC Programsits current operating cycle and permanently ceased generation operations in September 2018. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 14, 2017, the U.S. District Court31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the Northern Districtsale and decommissioning of Illinois dismissed two lawsuits challenging the ZEC program contained in FEJA. On July 17, 2017, the plaintiffs appealed the court's decisions to the U.S. Court of Appeals for the Seventh Circuit. Briefs were fully submitted on December 12, 2017 and the Court heard oral argument on January 3, 2018. At the argument, the Court asked for supplemental briefing, which was filed on January 26, 2018.
Additionally, on July 25, 2017, the U.S. District Court for the Southern District of New York dismissed a lawsuit challenging the ZEC program contained in the New York CES. On August 24, 2017, the plaintiffs appealed the decision to the Second Circuit. Briefing in the appeal was completed in December 2017, and oral argument is expected to take place in March 2018.
In addition, on November 30, 2016, a group of parties, including certain environmental groups and individuals, filed a Petition in New York State court seeking to invalidate the ZEC program. The Petition, which was amended on January 13, 2017, argued that the NYPSC did not have authority to establish the program and that it 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. Oral argument was held on June 19, 2017. On January 22, 2018, the court denied the motions to dismiss without commenting on the merits of the case. The case will now proceed to summary judgment upon filing of the full record.
The court decisions to date have upheld the ZEC programs which support Illinois's and New York's efforts to advance clean energy and preserve affordable and reliable energy resources for customers. See Note 3— Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding FEJA and the New York CES.
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 December 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-Cycle Gas Turbine Projects
In June 2017, Generation commenced commercial operations of two new combined-cycle gas turbines (CCGTs) at the Colorado Bend II and Wolf Hollow II Generating Stations in Texas. The two new CCGTs have added nearly 2,200 MWs of capacity to Generation’s fleet, enhancing Generation’s strategy to match generation to customer load. Generation invested approximately $1.5 billion over the past three years to complete the new plant construction, which utilizes new General Electric technology to make them among the cleanest, most efficient CCGTs in the nation.
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.
The following tables show the Utility Registrants’ completed and pending distribution rate case proceedings in 2017.
Completed Distribution Rate Case Proceedings
|
| | | | | | | | | | | | | |
Company | | Jurisdiction | | Approved Revenue Requirement Increase (in millions) | | Approved Return on Equity | | Completion Date | | Rate Effective Date |
ComEd | | Illinois (Electric)(a) | | $ | 96 |
| (b) | 8.4 | % | (c) | December 6, 2017 | | January 1, 2018 |
Pepco | | District of Columbia (Electric) | | $ | 37 |
| | 9.5 | % | | July 25, 2017 | | August 15, 2017 |
Pepco | | Maryland (Electric) | | $ | 32 |
| | 9.5 | % | | October 27, 2017 | | October 20, 2017 |
DPL | | Maryland (Electric) | | $ | 38 |
| | 9.6 | % | | February 15, 2017 | | February 15, 2017 |
DPL | | Delaware (Electric) | | $ | 31.5 |
| | 9.7 | % | | May 23, 2017 | | June 1, 2017 |
DPL | | Delaware (Natural Gas) | | $ | 4.9 |
| | 9.7 | % | | June 6, 2017 | | July 1, 2017 |
ACE | | New Jersey (Electric) | | $ | 43 |
| | 9.6 | % | | September 22, 2017 | | October 1, 2017 |
________
| |
(a) | Pursuant to EIMA, ComEd’s electric distribution rates are established through a performance-based formula through which ComEd is required to file an annual update on or before May 1, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for the year (annual reconciliation). |
| |
(b) | Reflects an increase of $78 million for the initial revenue requirement for 2017 and an increase of $18 million related to the annual reconciliation. |
| |
(c) | ComEd’s allowed ROE under its electric distribution formula rate is the annual average rate on 30-year treasury notes plus 580 basis points and is subject to reduction if ComEd does not deliver certain reliability and customer service benefits. The initial revenue requirement for 2017 reflects an allowed ROE of 8.40%, while the annual reconciliation reflects an allowed ROE of 8.34%, which is inclusive of a 6-basis-point performance penalty. |
Pending Distribution Rate Case Proceedings
|
| | | | | | | | | | | | | |
Company | | Jurisdiction | | Requested Revenue Requirement Increase (in millions) | | Requested Return on Equity | | Filing Date | | Expected Completion Timing |
Pepco | | Maryland (Electric) | | $ | 11 |
| (a) | 10.1 | % | | January 2, 2018 (Updated February 5, 2018) | | Third quarter 2018 |
Pepco | | District of Columbia (Electric) | | $ | 66 |
| (b) | 10.1 | % | | December 19, 2017 | | Fourth quarter 2018 |
DPL | | Maryland (Electric) | | $ | 19 |
| (b)(c) | 10.1 | % | (c) | July 14, 2017 (Updated on November 16, 2017) | | First quarter 2018 |
DPL | | Delaware (Electric) | | $ | 31 |
| (b) | 10.1 | % | | August 17, 2017 (Updated on October 18, 2017) | | Third quarter 2018 |
DPL | | Delaware (Natural Gas) | | $ | 11 |
| (b) | 10.1 | % | | August 17, 2017 (Updated on November 7, 2017) | | Fourth quarter 2018 |
________
| |
(a) | On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $31 million in TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. |
| |
(b) | By mid-February, Pepco and DPL will update their current distribution rate cases to reflect the TCJA impacts. |
| |
(c) | On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On January 5, 2018, the MDPSC held a hearing on the settlement agreement. DPL expects a decision in the matter in the first quarter of 2018, but cannot predict whether the MDPSC will approve the settlement agreement as filed or how much of the requested increase will be approved. |
Transmission Formula Rates
The following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's 2017 annual electric transmission formula rate filings:
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
Annual Transmission Filings(a) | ComEd | | BGE | | Pepco | | DPL | | ACE |
Initial revenue requirement increase | $ | 44 |
| | $ | 31 |
| | $ | 5 |
| | $ | 6 |
| | $ | 20 |
|
Annual reconciliation increase (decrease) | (33 | ) | | 3 |
| | 15 |
| | 8 |
| | 22 |
|
Dedicated facilities decrease(b) | — |
| | (8 | ) | | — |
| | — |
| | — |
|
Total revenue requirement increase | $ | 11 |
| | $ | 26 |
| | $ | 20 |
| | $ | 14 |
| | $ | 42 |
|
| | | | | | | | | |
Allowed return on rate base(c) | 8.43 | % | | 7.47 | % | | 7.92 | % | | 7.16 | % | | 8.02 | % |
Allowed ROE(d) | 11.50 | % | | 10.50 | % | | 10.50 | % | | 10.50 | % | | 10.50 | % |
_________
| |
(a) | All rates are effective June 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%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
PECO Transmission Formula Rate.On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate 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. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.
Oyster Creek. See Note 35 — Regulatory MattersMergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for further detailsadditional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committed to operate through May 2019. As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2019 due to the early retirement decisions.
|
| | | | | | | | |
| | Actual | | Projected(a) |
Income statement expense (pre-tax) | | 2018 | | 2019 |
Depreciation and Amortization(b) | | | | |
Accelerated depreciation(c) | | $ | 539 |
| | $ | 230 |
|
Accelerated nuclear fuel amortization | | 57 |
| | 5 |
|
Operating and maintenance(d) | | 32 |
| | 5 |
|
Total | | $ | 628 |
| | $ | 240 |
|
_________
| |
(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
| |
(b) | Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(c) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(d) | Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments. |
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for,
and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 4 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
The ISO-NE announced that it would take a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. On January 4, 2019, Generation notified ISO–NE that it will participate in the Forward Capacity Market auction for the 2022 – 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022–2023 capacity commitment period. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension Plan Merger
Effective January 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial
losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.
Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory proceedings.assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the twelve months ended December 31, 2018 are presented below:
|
| | | | | | | | | | |
| | | (in millions) |
| Customer Outages | | Incremental Operating & Maintenance | | Incremental Capital Expenditures |
Exelon | 1,727,000 |
| | $ | 88 |
| (b) | $ | 85 |
|
PECO | 750,000 |
| | 53 |
| | 34 |
|
BGE | 425,000 |
| | 31 |
| | 16 |
|
PHI(a) | 552,000 |
| | 4 |
| (b) | 35 |
|
Pepco | 182,000 |
| | 2 |
| (b) | 4 |
|
DPL | 138,000 |
| | 2 |
| (b) | 4 |
|
ACE | 232,000 |
| | — |
| (b) | 27 |
|
________
| |
(a) | PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE. |
| |
(b) | Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21 million, respectively. |
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. 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. On January 4, 2018, Westinghouse announced its agreement to be acquiredpurchased by an affiliate of Brookfield Business Partners.Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The deal, which requires bankruptcy court and regulatory approvals, is expected to close in in the third quarter oftransaction closed on August 1, 2018. Brookfield has informally indicated to Generation that it will assume all of Exelon'sExelon had contracts with Westinghouse. Generation is monitoring the bankruptcy and pending sale proceedingsWestinghouse primarily related to ensure that its rights are protected.
ExGen Renewables Holdings, LLC Transaction
On July 6, 2017, ExGen Renewables Holdings, LLC, a wholly owned subsidiaryGeneration's purchase of Generation, completed the sale of a 49% interest of ExGen Renewables Partners, LLC, a newly formed owner and operator of approximately 1,439 megawatts of Generation's operating wind and solar electric generating facilities. ExGen Renewables Holdings will be the managing member of ExGen Renewables Partners, LLC, and have day-to-day control and management over its renewable generation portfolio. The closing of the transaction was subject to certain regulatory approvals, including the Federal Energy Regulatory Commission (FERC) and the Public Utility Commission of Texas (PUCT) which were received during the second quarter of 2017. The sale price was $400 million plus immaterial working capital and other customary post-closing adjustments. The net proceeds, after approximately $100 million of income taxes, will be used to pay down debt and for general corporate purposes. Generation will continue to consolidate ExGen Renewables Partners, LLC and will record a noncontrolling interest on its Consolidated Balance Sheet for the investor's equity sharenuclear fuel, as well as earnings attributable toa variety of services and equipment purchases associated with the noncontrolling interest inoperation and maintenance of nuclear generating stations. In conjunction with the Consolidated Statementsconfirmation hearing, Exelon had filed a reservation of Operationsrights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and Comprehensive Income each period going forward.
Hurricanes Harvey, Irma and Maria Impacts
Althoughall Exelon subsidiaries provided substantial assistance to recovery efforts following Hurricanes Harvey and Irma, Hurricanes Harvey, Irma and Maria are not expected to have a material impactcontracts were assumed by Brookfield on the Registrants’ businesses or financial results given the limited operations in the areas affected by the storms.closing date.
Exelon’s Strategy and Outlook for 20182019 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 utilitiesThe Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
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 utilitiesUtility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Exelon utilitiesUtility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart metergrid 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-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors approved an updateda dividend policy providing an increasea raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, of which approximately 60% of run-rate savings was achieved by the
end of 2017 with the remainder to be fully realized in 2018. At leastApproximately 75% of the savings are expected to bewere related to Generation, with the remaining amount related to the Utility Registrants. Additionally, inIn November 2017, Exelon announced a new commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses.The PHI merger provides an opportunity to accelerateenhances Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $26$29 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives,technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $15$16 billion by the end of 2022.2023. The Utility Registrants invest in rate base where beneficial to customers and the community by
increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid InitiativesInvestments and infrastructure development and enhancement programs.
Competitive Energy Businesses.Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1.0 billion, $0.6 billion, $0.6 billion, $0.5$0.3 billion, $0.5$0.3 billion and $0.4$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.below and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
For further detailadditional information regarding the Registrants' liquidity for the year ended December 31, 2017,2018, see Liquidity and Capital Resources discussion below.
Project Financing
Generation utilizes individual project financings as a meansProject financing is used to finance the constructionhelp mitigate risk of variousspecific generating asset projects.assets. Project financing is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project areis paid back from the cash generated by the newly constructedspecific asset once operational.or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities of $0.2 billion as of December 31, 2018. See Note 13 — Debt and Credit Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results
of operations, cash flows and financial positions. See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further detailsadditional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
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,FERC Inquiry 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 for non-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. On June 20, 2017, the DC Circuit denied all the appeals.
MISO Capacity Market Results
On April 14, 2015, the 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 a non-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 its non-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 8 - Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on the impacts of the MISO announcement.
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 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. The EPSA parties have filed motions to expedite both proceedings. 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 in NYISO and PJM 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. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
DOE Notice of Proposed RulemakingResiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseloadbase-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE's NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On January 8, 2018, the FERC issued an order terminating the rulemaking docket that wasit initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. The FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. InterestedThereafter, interested parties may submitsubmitted reply comments within 30 days after the due date of the RTO/ISO responses.on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the New Jersey ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second
alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s financial statements.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active
participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Energy DemandWater Quality
Modest economic growth partially offsetUnder the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Section 316(b) of the Clean Water Act
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All 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 energy efficiency initiatives is resulting in flatrecent changes to declining load growth in electricitythe regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities and Salem.
On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the utilities.selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is decreaseno fixed compliance schedule, as this is left to the discretion of the state permitting director.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.
Pursuant to discussions with the NJDEP in projected load2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek before the expiration of its operating license in 2029. On September 17, 2018, Oyster Creek permanently ceased generation operations, and its cooling water intake system is no longer subject to Section 316(b). See Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for electricityadditional information about the sale and decommissioning of Oyster Creek.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for ComEd, PECO, BGE,cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and DPL,allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.
Salem
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an increaseenvironmental organization, and if successful, could result in projected loadadditional costs for electricityClean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Solid and Hazardous Waste
CERCLA provides for Pepcoimmediate response and ACE.removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Delaware, Illinois, Maryland, New Jersey and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE and their subsidiaries are, projecting load volumesor could become in the future, parties to increase (decrease)proceedings initiated by (0.5)%the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.
Environmental Remediation
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2019 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $46 million, consisting of $36 million, $6 million and $4 million at ComEd, PECO and BGE respectively. The Utility Registrants also have contingent liabilities for
environmental remediation of non-MGP contaminants (e.g., (0.5)%PCBs). As of December 31, 2018, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws.
In addition, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ Consolidated Financial Statements.
Global Climate Change
Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), (0.6)%, 1.5%, (1.5)% and 1.5%, respectively, in 2018has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to 2017.other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. As of December 31, 2018, fossil fuel generation represented approximately 29% of Exelon's owned generating capacity, while fossil fuel-fired generation during 2018 represented less than 11% of Exelon's overall generation on a MWh basis. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.
Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
International Climate Change Agreements. At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated.
Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
Under the Obama Administration, the EPA proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are currently being litigated. Under the Trump Administration, on October
16, 2017 the EPA proposed to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
Given litigation uncertainty and the absence of a final ACE rule, Exelon and Generation cannot at this time predict the impacts of regulation of existing power plants, or individual state responses to developments related to final resolution of the CPP and ACE regulations, or how developments will impact their future financial statements.
Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on resolution of the CPP and ACE regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Generation and our utilities operate are considering similar programs.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
Executive Officers of the Registrants as of February 8, 2019
Exelon
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Crane, Christopher M. | | 60 |
| | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | Chairman, ComEd, PECO & BGE | | 2012 - Present |
| | | | Chairman, PHI | | 2016 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | President, Generation | | 2008 - 2013 |
| | | | | | |
Cornew, Kenneth W. | | 53 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pramaggiore, Anne R. | | 60 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2018 - Present |
| | | | Chief Executive Officer, ComEd | | 2012 - 2018 |
| | | | President, ComEd | | 2009 - 2018 |
| | | | | | |
Dominguez, Joseph | | 56 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
Butler, Calvin G. | | 49 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Velazquez, David M. | | 59 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
Von Hoene Jr., William A. | | 65 |
| | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
Nigro, Joseph | | 54 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
Aliabadi, Paymon | | 56 |
| | Executive Vice President and Chief Risk Officer, Exelon | | 2013 - Present |
| | | | Managing Director, Gleam Capital Management | | 2012 - 2013 |
| | | | | | |
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Souza, Fabian E. | | 48 |
| | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
| | | | Vice President, Internal Audit and Advisory Services, The AES Corporation | | 2014 - 2015 |
| | | | Deputy Corporate Controller, The AES Corporation | | 2014 - 2014 |
| | | | Assistant Corporate Controller, Global Controllership, The AES Corporation | | 2013 - 2014 |
| | | | Controller, Global Utilities, The AES Corporation | | 2011 - 2013 |
Generation
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Cornew, Kenneth W. | | 53 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pacilio, Michael J. | | 58 |
| | Executive Vice President and Chief Operating Officer, Exelon Generation | | 2015 - Present |
| | | | President, Exelon Nuclear; Senior Vice President | | 2010 - 2015 |
| | | | and Chief Nuclear Officer, Generation | | |
| | | | | | |
Hanson, Bryan C | | 53 |
| | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation | | 2015 - Present |
| | | | | | |
McHugh, James | | 47 |
| | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
Barnes, John | | 55 |
| | Senior Vice President, Generation; President, Exelon Power | | 2018 - Present |
| | | | Senior Vice President, Generation, Senior Vice President and Chief Operating Officer, Exelon Power | | 2012 - 2018 |
| | | | | | |
Wright, Bryan P. | | 52 |
| | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | Senior Vice President, Corporate Finance, Exelon | | 2012 - 2013 |
| | | | | | |
Bauer, Matthew N. | | 42 |
| | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | Vice President of Power Finance, Exelon Power | | 2012 - 2014 |
ComEd
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Dominguez, Joseph | | 56 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Donnelly, Terence R. | | 58 |
| | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 |
| | | | | | |
Jones, Jeanne M. | | 39 |
| | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | Director, Finance, Exelon Nuclear | | 2013 - 2014 |
| | | | | | |
Park, Jane | | 46 |
| | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | Chief of Staff to President and Chief Executive Officer, ComEd | | 2012 - 2014 |
| | | | | | |
Gomez, Veronica | | 49 |
| | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
Marquez Jr., Fidel | | 57 |
| | Senior Vice President, Governmental and External Affairs, ComEd | | 2012 - Present |
| | | | | | |
McGuire, Timothy M. | | 60 |
| | Senior Vice President, Distribution Operations, ComEd | | 2016 - Present |
| | | | Vice President, Transmission and Substations, ComEd | | 2010 - 2016 |
| | | | | | |
Kozel, Gerald J. | | 46 |
| | Vice President, Controller, ComEd | | 2013 - Present |
| | | | Assistant Corporate Controller, Exelon | | 2012 - 2013 |
PECO
|
| | | | | | | |
Name | | Age | | Position | | Period |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
McDonald, John | | 61 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, Pepco Holdings | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
Stefani, Robert J. | | 44 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | Director, Corporate Development, Exelon | | 2012 - 2015 |
| | | | | | |
Murphy, Elizabeth A. | | 59 |
| | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
Webster Jr., Richard G. | | 57 |
| | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
Feldhake, Lauren | | 53 |
| | Vice President, Customer Operations, PECO | | 2017 - Present |
| | | | Director, Customer Care, PECO | | 2014 - 2017 |
| | | | Director, Customer Financial Operations, PECO | | 2009 - 2014 |
| | | | | | |
Diaz Jr., Romulo L. | | 72 |
| | Vice President and General Counsel, PECO | | 2012 - Present |
| | | | | | |
Bailey, Scott A. | | 42 |
| | Vice President and Controller, PECO | | 2012 - Present |
BGE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Butler, Calvin G. | | 49 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Woerner, Stephen J. | | 51 |
| | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | Senior Vice President, BGE | | 2009 - 2014 |
| | | | | | |
Vahos, David M. | | 46 |
| | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | Vice President and Controller, BGE | | 2012 - 2014 |
| | | | | | |
Núñez, Alexander G. | | 47 |
| | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 |
| | | | Director, State Affairs, BGE | | 2012 - 2013 |
| | | | | | |
Case, Mark D. | | 57 |
| | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present |
| | | | | | |
Oddoye, Rodney | | 42 |
| | Vice President, Customer Operations, BGE | | 2018 - Present |
| | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | Manager, Distribution Operations, BGE | | 2013 - 2015 |
| | | | | | |
Corse, John | | 58 |
| | Vice President and General Counsel, BGE | | 2018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
| | | | | | |
Holmes, Andrew W. | | 50 |
| | Vice President and Controller, BGE | | 2016 - Present |
| | | | Director, Generation Accounting, Exelon | | 2013 - 2016 |
| | | | Director, Derivatives and Technical Accounting, Exelon | | 2008 - 2013 |
PHI, Pepco, DPL and ACE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Velazquez, David M. | | 59 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present |
| | | | | | |
Anthony, J. Tyler | | 54 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
Barnett, Phillip S. | | 55 |
| | Senior Vice President, Chief Financial Officer and Treasurer PHI, Pepco, DPL and ACE | | 2018 - Present |
| | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 2018 |
| | | | | | |
Lavinson, Melissa | | 49 |
| | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | Vice President, Federal Affairs, PG&E Corporation | | 2012 - 2015 |
| | | | | | |
Stark, Wendy E. | | 46 |
| | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco DPL and ACE | | 2016 - 2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - Present |
| | | | | | |
McGowan, Kevin M. | | 57 |
| | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
Aiken, Robert | | 52 |
| | Vice President and Controller, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Vice President and Controller, Generation | | 2012 - 2016 |
Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond that Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC), which comprises officers of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon Board of Directors and the ComEd, PECO, BGE and PHI Boards of Directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors evaluates risks related to the generation business. The risk factors discussed below could adversely affect one or more of the Registrants’ consolidated financial statements and the market prices of their publicly traded securities. Each of the Registrants has disclosed the known material risks that affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed by a Registrant to be material that could adversely affect its performance or financial condition in the future.
Exelon's consolidated financial statements are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions
and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United States. Factors that affect the consolidated financial statements of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:
Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies and business models.
Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility regulatory business model cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.
Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.
A discussion of each of these risk categories and other risk factors is included below.
Market and Financial Factors
Generation is exposed to depressed prices in the wholesale and retail power markets, which could negatively affect its consolidated financial statements (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Exelon's nuclear plants.
Retail Competition
Competition. Generation’s retail operations compete for customers in a competitive environment, which affectaffects the margins that Generation can earn and the volumes that it is able to serve. The market experienced high price volatility in the first quarterIn periods of 2014 which contributed to bankruptcies and consolidations within the industry during the year. However, forwardsustained low natural gas and power prices are expected to remainand low and thus we expectmarket volatility, retail competitors to stay aggressive in their pursuit ofcan aggressively pursue market share because the barriers to entry can be low and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.
Strategic Policy AlignmentSustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s consolidated financial statements and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon's and Generation's result of operations through accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operating and maintenance expenses. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
In addition to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and could negatively affect its results of operations (Exelon and Generation).
Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry, including technologies related to energy generation, distribution and consumption (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation and energy
storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility Registrants' customers, the consolidated financial statements of the Utility Registrants could be negatively affected. Ultimately, if the Registrants are unable to manage the investments within the NDT funds and benefit plan assets and are unable to manage the related benefit plan liabilities and the related asset retirement obligations, their consolidated financial statements could be negatively impacted.
Unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could negatively impact the Registrants’ consolidated financial statements (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations. Disruptions in the capital and credit markets in the United States or abroad could adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash.
In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2018, approximately 19%, or $1.8 billion, 19%, or $1.8 billion, and 18%, or $1.7 billion of the Registrants’ available credit facilities were with European, Canadian and Asian banks, respectively. The credit facilities include $9.7 billion (including bilateral credit facilities and credit facilities for project
finance) in aggregate total commitments of which $8.0 billion was available as of December 31, 2018. As of December 31, 2018, there were no borrowings under Generation's bilateral credit facilities. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s and Generation’s consolidated financial statements.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation. Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy on such arrangements may be a significant assumption in performing impairment assessments of the project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.
A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s financial performance could be negatively affected by price volatility, availability and other risk factors associated with the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the consolidated financial statements for Generation.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its business or consolidated financial statements.
Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could impact the Registrants’ consolidated financial statements. (All Registrants).
Corporate Tax Reform. On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA, further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future consolidated financial statements.
The Utility Registrants have made their best estimate regarding the probability and timing of settlements of net regulatory liabilities established pursuant to the TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Utility Registrants’ future consolidated financial statements.
Tax reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates, including increases in the cost of purchased power and increases in natural gas prices for the Utility Registrants, and the impact of economic downturns could lead to greater expense for uncollectible customer balances. Additionally, increased rates could lead to decreased volumes delivered. Both of these factors could decrease Generation’s and the Utility Registrants' results from operations, cash flows or financial positions (All Registrants).
The impacts of economic downturns on the Utility Registrants' customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances', which would negatively affect the Utility Registrants' consolidated financial statements. Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances which could negatively affect Generation's consolidated financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Utility Registrants' current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s, PECO’s and ACE's costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas could result in declines in customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challenges by the regulators or the Utility Registrants as to the recoverability of these costs could have a material adverse effect in the Registrants’ consolidated financial statements. Also, the Utility Registrants' cash flows could be adversely affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
The effects of weather could impact the Registrants’ consolidated financial statements (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues
at PECO, DPL Delaware and ACE. Due to revenue decoupling, BGE, Pepco and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period, and are not affected by actual weather with the exception of major storms. Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. These extreme conditions could have detrimental effects in the Utility Registrants' consolidated financial statements. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Certain long-lived assets and other assets recorded on the Registrants’ statements of financial position could become impaired, which would result in write-offs of the impaired amounts (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon and Generation have significant balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assets for potential impairment. An impairment would require the Registrants to reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact in the Registrants’ consolidated financial statements.
As part of December 31, 2018, Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in 2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill remains at its strategic business planning process, Exelon routinely reviewsrecorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its hedging policy, dividend policy,carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.
Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, PHI’s, and ComEd’s goodwill, which could be material.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 6 — Property, Plant and Equipment, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 10 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset and goodwill impairments.
Exelon and its subsidiaries at times guarantee the performance of third parties, which could result in substantial costs in the event of non-performance by such third parties. In addition, the Registrants could have rights under agreements which obligate third parties to indemnify the Registrants for various obligations, and the Registrants could incur substantial costs in the event that the applicable Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection with the acquisition and divestiture of assets (All Registrants).
Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees. Such performance guarantees could have a material impact in the consolidated financial statements of the Registrant. Some of the Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities and such costs could adversely affect a Registrant’s consolidated financial statements.
Some of the Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations, which could adversely impact that Registrant’s consolidated financial statements. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee may have agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO and BGE may have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation or the transferee of Pepco's, DPL's or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims, which could impact that Utility Registrant's consolidated financial statements. In addition, the Utility Registrants may have residual liability under certain laws in connection with their former generation facilities.
Regulatory and Legislative Factors
The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to regulatory and legislative actions that adversely affect their consolidated financial statements. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations, cash flows or financial results (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and Generation’s consolidated financial statements are significantly affected by Generation's sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s and the Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations and could negatively impact their respective consolidated financial statements.
State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information, resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s consolidated financial statements. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Legislative and regulatory efforts in Illinois, New York and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through zero emission credit programs are subject to legal challenges and, if overturned, could negatively impact Exelon’s and Generation’s consolidated financial statements and result in the early retirement of certain of Generation’s nuclear plants.
Generation could be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 63% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for, policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.
FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin and capital spending plans, strengthrequirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities. Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other type of covered financial entity.
There are some rulemaking proceedings that have not yet been finalized, in particular, proposed rules on position limits that would apply to both Exchange-traded futures contracts and economically-equivalent over-the-counter swaps. Although the company would incur some costs associated with monitoring and compliance with such rules, it does not expect the rules to have a material impact on its business operations.
The Utility Registrants could also be subject to some Dodd-Frank requirements to the extent they were to enter into swaps. However, at this time, management of the Utility Registrants continue to expect that their companies will not be materially affected by Dodd-Frank.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased
costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.
If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.
In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.
In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval.
The Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs or earn an adequate return and could have a material adverse effect in the Utility Registrants' consolidated financial statements. See Note 4 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the consolidated financial statements of Generation and the Utility Registrants (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact the Utility Registrants if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.
The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon and the Utility Registrants (Exelon and the Utility Registrants).
As of December 31, 2018, Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See Note 1 — Significant Accounting Policies, Note 4 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.
Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change (Exelon and Generation).
Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission
allowance credits. See ITEM 1. BUSINESS — Global Climate Change and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding climate change.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. As operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants have large consumer customer bases and as a result could be the subject of public criticism focused on the operability of their assets and infrastructure and quality of their service. Adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs). The imposition of any of the foregoing could have a material negative impact on the Registrants' business or consolidated financial statements.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could negatively impact their consolidated financial statements (All Registrants).
The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue or restrict existing business activities, any of which could have a material adverse effect in the Registrants’ consolidated financial statements.
Generation could be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations and profitability of its balance sheetnuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs and significantly affect Generation’s consolidated financial statements. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, such as the one previously considered at Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation's consolidated financial statements. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
Operational Factors
The Registrants’ employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near their operations. As a result, employees, contractors, customers and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters, such as seismic activity, fires resulting from natural causes such as lightning, extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, the Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit metrics,crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain, which could adversely affect the Registrants’ consolidated financial statements and sufficiencytheir ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected, resulting in decreased service levels and increased costs.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shutdown the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s consolidated financial statements. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect in Generation’s consolidated financial statements. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly adversely affect Generation’s consolidated financial statements.
Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through
mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $14.1 billion limit for a single incident.
Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the NDT funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. No assurance can be given that the costs of such decommissioning will not substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is making contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its liquidity position,other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s consolidated financial statements could be significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. Ultimately, if the investments held by performing various stress tests with differing variables,Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as commodity price movements,providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s consolidated financial statements could be significantly adversely affected. Additionally, if the pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.
If the expected value in the NDT funds for any nuclear unit subject to the regulatory agreements with the ICC is expected to not exceed the total decommissioning obligation for that unit, the accounting to offset decommissioning-
related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s consolidated financial statements could be material. For the nuclear units subject to the regulatory agreements with the PAPUC, any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s consolidated financial statements could be material. If the accounting to offset decommissioning-related activities is discontinued, any remaining balances in noncurrent payables to affiliates at Generation and ComEd's or PECO’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact in Generation’s Consolidated Statement of Operations and Comprehensive Income.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. The license for the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired on September 1, 2014. FERC issued an annual license, effective as of the expiration of the previous license. If FERC does not issue a license prior to the expiration of the annual license, the annual license renews automatically. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic and significantly affect Generation’s consolidated financial statements. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants’ respective consolidated financial statements could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure of electric or gas systems, generation facilities or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' operating costs, and customers’ and regulators’ opinions of the Utility Registrants are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities, including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, the Utility Registrants' consolidated financial statements could be negatively impacted. Furthermore, if
any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, the Utility Registrants' financial results could also be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory oversight and the Utility Registrants' maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, and those damages could be material to ComEd’s consolidated financial statements.
The Utility Registrants' respective ability to deliver electricity, their operating costs and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
The electricity transmission facilities of the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid that is operated by PJM RTO. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions at other utilities will not cause interruptions in the Utility Registrants’ service areas. If the Utility Registrants were to suffer such a service interruption, it could have a negative impact in their and Exelon’s consolidated financial statements.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in margin-related transactions,RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of Exelon or another Registrant and its customer supply activities could be adversely affected, customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its subsidiaries could be subject to legal claims, loss of revenues, increased costs, operations shutdown, etc., any of which could contribute to the loss of customers and have a negative impact on the business and/or consolidated financial statements. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. The Utility Registrants' deployment of smart meters throughout their service territories could increase the
risk of damage from an intentional disruption of the system by third parties. In addition, new or updated security regulations or unforeseen threat sources could require changes in hedging practices,current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ consolidated financial statements (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their consolidated financial statements could be negatively impacted.
The Registrants could make investments in new business initiatives, including initiatives mandated by regulators, and markets that may not be successful, and acquisitions could not achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into liquefied natural gas. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated Smart Grid and utility of the future initiatives and other non-regulatory mandated initiatives. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity and obsolescence of technology. Due to these risks, no assurance can be given that such initiatives will be successful and will not have a material adverse effect in the Utility Registrants' consolidated financial statements.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts which could impact the Registrants’ results of operations (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
|
| |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2018:
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Braidwood | Midwest | Braidwood, IL | 2 |
| | Uranium | Base-load | 2,386 |
| |
Byron | Midwest | Byron, IL | 2 |
| | Uranium | Base-load | 2,347 |
| |
LaSalle | Midwest | Seneca, IL | 2 |
| | Uranium | Base-load | 2,320 |
| |
Dresden | Midwest | Morris, IL | 2 |
| | Uranium | Base-load | 1,845 |
| |
Quad Cities | Midwest | Cordova, IL | 2 |
| 75 |
| Uranium | Base-load | 1,403 |
| (e) |
Clinton | Midwest | Clinton, IL | 1 |
| | Uranium | Base-load | 1,069 |
| |
Michigan Wind 2 | Midwest | Sanilac Co., MI | 50 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Beebe | Midwest | Gratiot Co., MI | 34 |
| 51 |
| Wind | Base-load | 42 |
| (e)(h) |
Michigan Wind 1 | Midwest | Huron Co., MI | 46 |
| 51 |
| Wind | Base-load | 35 |
| (e)(g) |
Harvest 2 | Midwest | Huron Co., MI | 33 |
| 51 |
| Wind | Base-load | 30 |
| (e)(g) |
Harvest | Midwest | Huron Co., MI | 32 |
| 51 |
| Wind | Base-load | 27 |
| (e)(g) |
Beebe 1B | Midwest | Gratiot Co., MI | 21 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Ewington | Midwest | Jackson Co., MN | 10 |
| 99 |
| Wind | Base-load | 20 |
| (e) |
Marshall | Midwest | Lyon Co., MN | 9 |
| 99 |
| Wind | Base-load | 19 |
| (e) |
City Solar | Midwest | Chicago, IL | 1 |
| | Solar | Base-load | 9 |
| |
Solar Ohio | Midwest | Toledo, OH | 2 |
| | Solar | Base-load | 4 |
| |
Blue Breezes | Midwest | Faribault Co., MN | 2 |
| | Wind | Base-load | 3 |
| |
CP Windfarm | Midwest | Faribault Co., MN | 2 |
| 51 |
| Wind | Base-load | 2 |
| (e)(g) |
Southeast Chicago | Midwest | Chicago, IL | 8 |
| | Gas | Peaking | 296 |
| (k) |
Clinton Battery Storage | Midwest | Blanchester, OH | 1 |
| | Energy Storage | Peaking | 10 |
| |
Total Midwest | | | | | | | 11,939 |
| |
| | | | | | | | |
Limerick | Mid-Atlantic | Sanatoga, PA | 2 |
| | Uranium | Base-load | 2,317 |
| |
Peach Bottom | Mid-Atlantic | Delta, PA | 2 |
| 50 |
| Uranium | Base-load | 1,324 |
| (e) |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 2 |
| 42.59 |
| Uranium | Base-load | 1,002 |
| (e) |
Calvert Cliffs | Mid-Atlantic | Lusby, MD | 2 |
| 50.01 |
| Uranium | Base-load | 895 |
| (e)(f) |
Three Mile Island | Mid-Atlantic | Middletown, PA | 1 |
| | Uranium | Base-load | 837 |
| (j) |
Conowingo | Mid-Atlantic | Darlington, MD | 11 |
| | Hydroelectric | Base-load | 572 |
| |
Criterion | Mid-Atlantic | Oakland, MD | 28 |
| 51 |
| Wind | Base-load | 36 |
| (e)(g) |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Fair Wind | Mid-Atlantic | Garrett County, MD | 12 |
| | Wind | Base-load | 30 |
| |
Solar Maryland MC | Mid-Atlantic | Various, MD | 40 |
| | Solar | Base-load | 36 |
| |
Fourmile | Mid-Atlantic | Garrett County, MD | 16 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Solar New Jersey 1 | Mid-Atlantic | Various, NJ | 5 |
| | Solar | Base-load | 18 |
| |
Solar New Jersey 2 | Mid-Atlantic | Various, NJ | 2 |
| | Solar | Base-load | 11 |
| |
Solar Horizons | Mid-Atlantic | Emmitsburg, MD | 1 |
| 51 |
| Solar | Base-load | 8 |
| (e)(g) |
Solar Maryland | Mid-Atlantic | Various, MD | 11 |
| | Solar | Base-load | 8 |
| |
Solar Maryland 2 | Mid-Atlantic | Various, MD | 3 |
| | Solar | Base-load | 8 |
| |
Constellation New Energy | Mid-Atlantic | Gaithersburg, MD | 1 |
| | Solar | Base-load | 5 |
| |
Solar Federal | Mid-Atlantic | Trenton, NJ | 1 |
| | Solar | Base-load | 5 |
| |
Solar New Jersey 3 | Mid-Atlantic | Middle Township, NJ | 5 |
| 51 |
| Solar | Base-load | 1 |
| (e)(g) |
Solar DC | Mid-Atlantic | District of Columbia | 1 |
| | Solar | Base-load | 1 |
| |
Muddy Run | Mid-Atlantic | Drumore, PA | 8 |
| | Hydroelectric | Intermediate | 1,070 |
| |
Eddystone 3, 4 | Mid-Atlantic | Eddystone, PA | 2 |
| | Oil/Gas | Intermediate | 760 |
| |
Perryman | Mid-Atlantic | Aberdeen, MD | 5 |
| | Oil/Gas | Peaking | 404 |
| |
Croydon | Mid-Atlantic | West Bristol, PA | 8 |
| | Oil | Peaking | 391 |
| |
Handsome Lake | Mid-Atlantic | Kennerdell, PA | 5 |
| | Gas | Peaking | 268 |
| |
Notch Cliff | Mid-Atlantic | Baltimore, MD | 8 |
| | Gas | Peaking | 117 |
| (k) |
Westport | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 116 |
| (k) |
Richmond | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 98 |
| |
Gould Street | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 97 |
| (k) |
Philadelphia Road | Mid-Atlantic | Baltimore, MD | 4 |
| | Oil | Peaking | 61 |
| |
Eddystone | Mid-Atlantic | Eddystone, PA | 4 |
| | Oil | Peaking | 60 |
| |
Fairless Hills | Mid-Atlantic | Fairless Hills, PA | 2 |
| | Landfill Gas | Peaking | 60 |
| (k) |
Delaware | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 56 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Southwark | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 52 |
| |
Falls | Mid-Atlantic | Morrisville, PA | 3 |
| | Oil | Peaking | 51 |
| |
Moser | Mid-Atlantic | Lower PottsgroveTwp., PA | 3 |
| | Oil | Peaking | 51 |
| |
Riverside | Mid-Atlantic | Baltimore, MD | 2 |
| | Oil | Peaking | 39 |
| (k)(l) |
Chester | Mid-Atlantic | Chester, PA | 3 |
| | Oil | Peaking | 39 |
| |
Schuylkill | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 30 |
| |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 1 |
| 42.59 |
| Oil | Peaking | 16 |
| (e) |
Pennsbury | Mid-Atlantic | Morrisville, PA | 2 |
| | Landfill Gas | Peaking | 4 |
| (e) |
Bethlehem | Mid-Atlantic | Bethlehem, PA | 1 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Eastern | Mid-Atlantic | Bethlehem, PA | 3 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Total Mid-Atlantic | | | | | | | 10,982 |
| |
| | | | | | | | |
Whitetail | ERCOT | Webb County, TX | 57 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Sendero | ERCOT | Jim Hogg and Zapata County, TX | 39 |
| 51 |
| Wind | Base-load | 40 |
| (e)(g) |
Constellation Solar Texas | Other | Various, TX | 11 |
| | Solar | Base-load | 13 |
| |
Colorado Bend II | ERCOT | Wharton, TX | 3 |
| | Gas | Intermediate | 1,088 |
| |
Wolf Hollow II | ERCOT | Granbury, TX | 3 |
| | Gas | Intermediate | 1,064 |
| |
Handley 3 | ERCOT | Fort Worth, TX | 1 |
| | Gas | Intermediate | 395 |
| |
Handley 4, 5 | ERCOT | Fort Worth, TX | 2 |
| | Gas | Peaking | 870 |
| |
Total ERCOT | | | | | | | 3,516 |
| |
| | | | | | | | |
Solar Massachusetts | New England | Various, MA | 10 |
| | Solar | Base-load | 7 |
| |
Holyoke Solar | New England | Various, MA | 2 |
| | Solar | Base-load | 5 |
| |
Solar Net Metering | New England | Uxbridge, MA | 1 |
| | Solar | Base-load | 2 |
| |
Solar Connecticut | New England | Various, CT | 1 |
| | Solar | Base-load | 1 |
| |
Mystic 8, 9 | New England | Charlestown, MA | 6 |
| | Gas | Intermediate | 1,417 |
| |
Mystic 7 | New England | Charlestown, MA | 1 |
| | Oil/Gas | Intermediate | 573 |
| (m) |
Wyman | New England | Yarmouth, ME | 1 |
| 5.9 |
| Oil | Intermediate | 35 |
| (e) |
West Medway | New England | West Medway, MA | 3 |
| | Oil | Peaking | 123 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Framingham | New England | Framingham, MA | 3 |
| | Oil | Peaking | 31 |
| |
Mystic Jet | New England | Charlestown, MA | 1 |
| | Oil | Peaking | 9 |
| (m) |
Total New England | | | | | | | 2,203 |
| |
| | | | | | | | |
Nine Mile Point | New York | Scriba, NY | 2 |
| 50.01 |
| Uranium | Base-load | 838 |
| (e)(f) |
FitzPatrick | New York | Scriba, NY | 1 |
| | Uranium | Base-load | 842 |
| |
Ginna | New York | Ontario, NY | 1 |
| 50.01 |
| Uranium | Base-load | 288 |
| (e)(f) |
Solar New York | New York | Bethlehem, NY | 1 |
| | Solar | Base-load | 3 |
| |
Total New York | | | | | | | 1,971 |
| |
| | | | | | | | |
Antelope Valley | Other | Lancaster, CA | 1 |
| | Solar | Base-load | 242 |
| |
Bluestem | Other | Beaver County, OK | 60 |
| 51 |
| Wind | Base-load | 101 |
| (e)(g)(h) |
Exelon Wind 4 | Other | Gruver, TX | 38 |
| | Wind | Base-load | 80 |
| |
Shooting Star | Other | Kiowa County, KS | 65 |
| 51 |
| Wind | Base-load | 53 |
| (e)(g) |
Albany Green Energy | Other | Albany, GA | 1 |
| 99 |
| Biomass | Base-load | 52 |
| (i) |
Solar Arizona | Other | Various, AZ | 127 |
| | Solar | Base-load | 46 |
| |
Bluegrass Ridge | Other | King City, MO | 27 |
| 51 |
| Wind | Base-load | 29 |
| (e)(g) |
California PV Energy 2 | Other | Various, CA | 89 |
| | Solar | Base-load | 27 |
| |
Conception | Other | Barnard, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Cow Branch | Other | Rock Port, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Solar Arizona 2 | Other | Various, AZ | 25 |
| | Solar | Base-load | 23 |
| |
California PV Energy | Other | Various, CA | 53 |
| | Solar | Base-load | 21 |
| |
Mountain Home | Other | Glenns Ferry, ID | 20 |
| 51 |
| Wind | Base-load | 21 |
| (e)(g) |
High Mesa | Other | Elmore Co., ID | 19 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Echo 1 | Other | Echo, OR | 21 |
| 50.49 |
| Wind | Base-load | 17 |
| (e)(g) |
Sacramento PV Energy | Other | Sacramento, CA | 4 |
| 51 |
| Solar | Base-load | 15 |
| (e)(g) |
Cassia | Other | Buhl, ID | 14 |
| 51 |
| Wind | Base-load | 15 |
| (e)(g) |
Wildcat | Other | Lovington, NM | 13 |
| 51 |
| Wind | Base-load | 14 |
| (e)(g) |
Echo 2 | Other | Echo, OR | 10 |
| 51 |
| Wind | Base-load | 10 |
| (e)(g) |
Exelon Wind 5 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 6 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 7 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 8 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 9 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 10 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 11 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
High Plains | Other | Panhandle, TX | 8 |
| 99.5 |
| Wind | Base-load | 10 |
| (e) |
Solar Georgia 2 | Other | Various, GA | 8 |
| | Solar | Base-load | 10 |
| |
Tuana Springs | Other | Hagerman, ID | 8 |
| 51 |
| Wind | Base-load | 9 |
| (e)(g) |
Solar Georgia | Other | Various, GA | 10 |
| | Solar | Base-load | 8 |
| |
Greensburg | Other | Greensburg, KS | 10 |
| 51 |
| Wind | Base-load | 7 |
| (e)(g) |
Outback Solar | Other | Christmas Valley, OR | 1 |
| | Solar | Base-load | 6 |
| |
Echo 3 | Other | Echo, OR | 6 |
| 50.49 |
| Wind | Base-load | 5 |
| (e)(g) |
Three Mile Canyon | Other | Boardman, OR | 6 |
| 51 |
| Wind | Base-load | 5 |
| (e)(g) |
Loess Hills | Other | Rock Port, MO | 4 |
| | Wind | Base-load | 5 |
| |
California PV Energy 3 | Other | Various, CA | 10 |
| | Solar | Base-load | 5 |
| |
Mohave Sunrise Solar | Other | Fort Mohave, AZ | 1 |
| | Solar | Base-load | 5 |
| |
Denver Airport Solar | Other | Denver, CO | 1 |
| 51 |
| Solar | Base-load | 2 |
| (e)(g) |
Hillabee | Other | Alexander City, AL | 3 |
| | Gas | Intermediate | 753 |
| |
Grande Prairie | Other | Alberta, Canada | 1 |
| | Gas | Peaking | 105 |
| |
SEGS 4, 5, 6 | Other | Boron, CA | 3 |
| 4.2-12.2 |
| Solar | Peaking | 9 |
| (e) |
Total Other | | | | | | | 1,852 |
| |
Total | | | | | | | 32,463 |
| |
__________
| |
(a) | All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors. |
| |
(b) | 100%, unless otherwise indicated. |
| |
(c) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. |
| |
(d) | For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity. |
| |
(e) | Net generation capacity is stated at proportionate ownership share. |
| |
(f) | Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2. |
| |
(g) | Reflects the sale of 49% of EGRP to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(h) | EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. |
| |
(i) | Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity. |
| |
(j) | Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(k) | Generation has agreed to retire and cease generation operations at the Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit 8), Westport and Pennsbury units on or before June 1, 2020. |
| |
(l) | Generation plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019. |
| |
(m) | Generation plans to retire and cease generation operation at the Mystic 7 and Mystic Jet units on or about June 1, 2022. |
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
ComEd
ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ComEd’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
765,000 | | 90 |
345,000 | | 2,716 |
138,000 | | 2,209 |
ComEd’s electric distribution system includes 35,398 circuit miles of overhead lines and 32,010 circuit miles of underground lines.
First Mortgage and Insurance
The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First Mortgage Bonds are issued.
ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ComEd.
PECO
PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | | |
Voltage (Volts) | | Circuit Miles | |
500,000 | | 188 | (a) |
230,000 | | 549 | |
138,000 | | 135 | |
69,000 | | 181 | |
__________
| |
(a) | In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey. |
PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,367 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 9 |
|
Distribution | 6,912 |
|
Service piping | 6,377 |
|
Total | 13,298 |
|
PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 160 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 30 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.
First Mortgage and Insurance
The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.
PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of PECO.
BGE
BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 218 |
230,000 | | 358 |
138,000 | | 55 |
115,000 | | 706 |
BGE’s electric distribution system includes 9,191 circuit miles of overhead lines and 17,295 circuit miles of underground lines.
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 161 |
|
Distribution | 7,348 |
|
Service piping | 6,305 |
|
Total | 13,814 |
|
BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,056 mmcf and a send-out capacity of 332 mmcf/day and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.
Property Insurance
BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of BGE.
Pepco
Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 142 |
230,000 | | 767 |
138,000 | | 61 |
115,000 | | 38 |
Pepco’s electric distribution system includes approximately 4,127 circuit miles of overhead lines and 7,039 circuit miles of underground lines. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.
First Mortgage and Insurance
The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First Mortgage Bonds are issued.
Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of Pepco.
DPL
DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
DPL’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows: |
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 16 |
230,000 | | 471 |
138,000 | | 586 |
69,000 | | 569 |
DPL’s electric distribution system includes approximately 6,031 circuit miles of overhead lines and 6,298 circuit miles of underground lines. DPL also owns and operates a distribution system control center in New Castle, Delaware.
Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission (a) | 8 |
|
Distribution | 2,065 |
|
Service piping | 1,398 |
|
Total | 3,471 |
|
___________
| |
(a) | DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities. |
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 250 mmcf and an emergency sendout capability of 36 mmcf/day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 158 mmcf/day.
First Mortgage and Insurance
The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First Mortgage Bonds are issued.
DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of DPL.
ACE
ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ACE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | — |
230,000 | | 221 |
138,000 | | 239 |
69,000 | | 663 |
ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,927 circuit miles of underground lines. ACE also owns and operates a distribution system control center in Mays Landing, New Jersey.
First Mortgage and Insurance
The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First Mortgage Bonds are issued.
ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ACE.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
|
| |
ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share data, unless otherwise noted)
|
| |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the New York Stock Exchange (trading symbol: EXC). As of January 31, 2019, there were 969,745,933 shares of common stock outstanding and approximately 99,857 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the impacts of hypothetical credit downgrades.S&P Utility Index, for the period 2014 through 2018.
Exelon's Board of Directors declared first, second, third and fourth quarter 2017 dividends of $0.3275 per share eachThis performance chart assumes:
$100 invested on Exelon'sDecember 31, 2013 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and
All dividends are reinvested.
|
| | | | | | |
Value of Investment at December 31, |
| 2013 | 2014 | 2015 | 2016 | 2017 | 2018 |
Exelon Corporation | $100 | $140.61 | $109.44 | $145.34 | $167.22 | $197.86 |
S&P 500 | $100 | $113.68 | $115.24 | $129.02 | $157.17 | $150.27 |
S&P Utilities | $100 | $128.98 | $122.73 | $142.72 | $160.00 | $166.57 |
Generation
As of January 31, 2019, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2019, there were 127,021,331 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2019, in addition to Exelon, there were 294 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2019, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2019, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2019, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2019, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2019, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2019, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the first quarter 2018District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s
senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends declared was $0.3450 per share. The dividends for the first, second, third and fourth quarter 2017 werecan be paid on March 10, 2017, June 9, 2017, September 8, 2017 and December 8, 2017, respectively. The first quarter 2018 dividend is payable on March 9, 2018.if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Hedging StrategyAt December 31, 2018, Exelon had retained earnings of $14,766 million, including Generation’s undistributed earnings of $3,724 million, ComEd’s retained earnings of $1,337 million consisting of retained earnings appropriated for future dividends of $2,976 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,242 million, BGE’s retained earnings of $1,640 million, and PHI's undistributed earnings of $62 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2018 and 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 |
(per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
Exelon | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
|
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's quarterly common dividend payments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 |
(in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter |
Generation | $ | 313 |
| | $ | 311 |
| | $ | 189 |
| | $ | 188 |
| | $ | 165 |
| | $ | 164 |
| | $ | 166 |
| | $ | 164 |
|
ComEd | 114 |
| | 116 |
| | 115 |
| | 114 |
| | 106 |
| | 105 |
| | 106 |
| | 105 |
|
PECO | 6 |
| | 7 |
| | 6 |
| | 287 |
| | 72 |
| | 72 |
| | 72 |
| | 72 |
|
BGE | 52 |
| | 52 |
| | 53 |
| | 52 |
| | 50 |
| | 49 |
| | 50 |
| | 49 |
|
PHI | 94 |
| | 123 |
| | 38 |
| | 71 |
| | 44 |
| | 136 |
| | 62 |
| | 69 |
|
Pepco | 41 |
| | 78 |
| | 25 |
| | 25 |
| | — |
| | 75 |
| | 28 |
| | 30 |
|
DPL | 38 |
| | 18 |
| | 4 |
| | 36 |
| | 30 |
| | 28 |
| | 24 |
| | 30 |
|
ACE | 13 |
| | 27 |
| | 10 |
| | 9 |
| | 15 |
| | 31 |
| | 12 |
| | 10 |
|
First Quarter 2019 Dividend
On February 5, 2019, the Exelon Board of Directors declared a first quarter 2019 regular quarterly dividend of $0.3625 per share on Exelon’s common stock payable on March 8, 2019, to shareholders of record of Exelon at the end of the day on February 20, 2019.
|
| |
ITEM 6. | SELECTED FINANCIAL DATA |
Exelon
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s policyConsolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions, except per share data) | 2018 | | 2017(c, d) | | 2016(a, c, d) | | 2015(c) | | 2014(b,c) |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 35,985 |
| | $ | 33,565 |
| | $ | 31,366 |
| | $ | 29,447 |
| | $ | 27,429 |
|
Operating income | 3,898 |
| | 4,395 |
| | 3,212 |
| | 4,554 |
| | 3,210 |
|
Net income | 2,084 |
|
| 3,876 |
|
| 1,196 |
|
| 2,250 |
|
| 1,820 |
|
Net income attributable to common shareholders | 2,010 |
| | 3,786 |
| | 1,121 |
| | 2,269 |
| | 1,623 |
|
Earnings per average common share (diluted): | | | | | | | | | |
Net income | $ | 2.07 |
| | $ | 3.99 |
| | $ | 1.21 |
| | $ | 2.54 |
| | $ | 1.88 |
|
Dividends per common share | $ | 1.38 |
| | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| | $ | 1.24 |
|
__________
| |
(a) | The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016. |
| |
(b) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(c) | Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(d) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015(a) | | 2014(a) |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 13,360 |
| | $ | 11,896 |
| | $ | 12,451 |
| | $ | 15,334 |
| | $ | 11,853 |
|
Property, plant and equipment, net | 76,707 |
| | 74,202 |
| | 71,555 |
| | 57,439 |
| | 52,170 |
|
Total assets | 119,666 |
|
| 116,770 |
|
| 114,952 |
|
| 95,384 |
|
| 86,416 |
|
Current liabilities | 11,404 |
| | 10,798 |
| | 13,463 |
| | 9,118 |
| | 8,762 |
|
Long-term debt, including long-term debt to financing trusts | 34,465 |
| | 32,565 |
| | 32,216 |
| | 24,286 |
| | 19,853 |
|
Shareholders’ equity | 30,764 |
| | 29,896 |
| | 25,860 |
| | 25,793 |
| | 22,608 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to hedge commodity riskand should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017(b) | | 2016(b) | | 2015 | | 2014(a) |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 20,437 |
| | $ | 18,500 |
| | $ | 17,757 |
| | $ | 19,135 |
| | $ | 17,393 |
|
Operating income | 975 |
| | 947 |
| | 820 |
| | 2,275 |
| | 1,176 |
|
Net income | 443 |
| | 2,798 |
| | 550 |
| | 1,340 |
| | 1,019 |
|
__________
| |
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(b) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 8,433 |
| | $ | 6,882 |
| | $ | 6,567 |
| | $ | 6,342 |
| | $ | 7,311 |
|
Property, plant and equipment, net | 23,981 |
| | 24,906 |
| | 25,585 |
| | 25,843 |
| | 23,028 |
|
Total assets | 47,556 |
|
| 48,457 |
|
| 47,022 |
|
| 46,529 |
|
| 44,951 |
|
Current liabilities | 5,769 |
| | 4,191 |
| | 5,689 |
| | 4,933 |
| | 4,459 |
|
Long-term debt, including long-term debt to affiliates | 7,887 |
| | 8,644 |
| | 8,124 |
| | 8,869 |
| | 7,582 |
|
Member’s equity | 13,204 |
| | 13,669 |
| | 11,505 |
| | 11,635 |
| | 12,718 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
ComEd
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 5,882 |
| | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| | $ | 4,564 |
|
Operating income | 1,146 |
| | 1,323 |
| | 1,205 |
| | 1,017 |
| | 980 |
|
Net income | 664 |
| | 567 |
| | 378 |
| | 426 |
| | 408 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 1,570 |
| | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| | $ | 1,723 |
|
Property, plant and equipment, net | 22,058 |
| | 20,723 |
| | 19,335 |
| | 17,502 |
| | 15,793 |
|
Total assets | 31,213 |
|
| 29,726 |
|
| 28,335 |
|
| 26,532 |
|
| 25,358 |
|
Current liabilities | 1,925 |
| | 2,294 |
| | 2,938 |
| | 2,766 |
| | 1,923 |
|
Long-term debt, including long-term debt to financing trusts | 8,006 |
| | 6,966 |
| | 6,813 |
| | 6,049 |
| | 5,870 |
|
Shareholders’ equity | 10,247 |
| | 9,542 |
| | 8,725 |
| | 8,243 |
| | 7,907 |
|
PECO
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 3,038 |
| | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| | $ | 3,094 |
|
Operating income | 587 |
| | 655 |
| | 702 |
| | 630 |
| | 572 |
|
Net income | 460 |
| | 434 |
| | 438 |
| | 378 |
| | 352 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 782 |
| | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| | $ | 645 |
|
Property, plant and equipment, net | 8,610 |
| | 8,053 |
| | 7,565 |
| | 7,141 |
| | 6,801 |
|
Total assets | 10,642 |
|
| 10,170 |
|
| 10,831 |
|
| 10,367 |
|
| 9,860 |
|
Current liabilities | 809 |
| | 1,267 |
| | 727 |
| | 944 |
| | 653 |
|
Long-term debt, including long-term debt to financing trusts | 3,268 |
| | 2,587 |
| | 2,764 |
| | 2,464 |
| | 2,416 |
|
Shareholder's equity | 3,820 |
| | 3,577 |
| | 3,415 |
| | 3,236 |
| | 3,121 |
|
BGE
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 3,169 |
| | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| | $ | 3,165 |
|
Operating income | 474 |
| | 614 |
| | 550 |
| | 558 |
| | 439 |
|
Net income | 313 |
| | 307 |
| | 294 |
| | 288 |
| | 211 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 786 |
| | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| | $ | 951 |
|
Property, plant and equipment, net | 8,243 |
| | 7,602 |
| | 7,040 |
| | 6,597 |
| | 6,204 |
|
Total assets | 9,716 |
|
| 9,104 |
|
| 8,704 |
|
| 8,295 |
|
| 8,056 |
|
Current liabilities | 774 |
| | 760 |
| | 707 |
| | 1,134 |
| | 794 |
|
Long-term debt, including long-term debt to financing trusts | 2,876 |
| | 2,577 |
| | 2,533 |
| | 1,732 |
| | 2,109 |
|
Shareholder's equity | 3,354 |
| | 3,141 |
| | 2,848 |
| | 2,687 |
| | 2,563 |
|
PHI
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | March 24 to December 31 | | | January 1 to March 23, | | For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | |
Operating revenues | $ | 4,805 |
| | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $4,935 | | $ | 4,808 |
|
Operating income | 650 |
| | 769 |
| | 93 |
| | | 105 |
| | 673 |
| | 605 |
|
Net income (loss) from continuing operations | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| | 242 |
|
Net income (loss) | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 327 |
| | 242 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| December 31, | | | December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | | 2015 |
Balance Sheet data(a): | | | | | | | | |
Current assets | $ | 1,533 |
| | $ | 1,551 |
| | $ | 1,838 |
| | | $ | 1,474 |
|
Property, plant and equipment, net | 13,446 |
| | 12,498 |
| | 11,598 |
| | | 10,864 |
|
Total assets | 21,984 |
| | 21,247 |
| | 21,025 |
| | | 16,188 |
|
Current liabilities | 1,592 |
| | 1,931 |
| | 2,284 |
| | | 2,327 |
|
Long-term debt | 6,134 |
| | 5,478 |
| | 5,645 |
| | | 4,823 |
|
Preferred Stock | — |
| | — |
| | — |
| | | 183 |
|
Member’s equity/Shareholders' equity | 9,282 |
| | 8,825 |
| | 8,016 |
| | | 4,413 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above. |
Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 2,239 |
| | $ | 2,158 |
| | $ | 2,186 |
| | $ | 2,129 |
| | $ | 2,055 |
|
Operating income | 320 |
| | 399 |
| | 174 |
| | 385 |
| | 349 |
|
Net income | 210 |
| | 205 |
| | 42 |
| | 187 |
| | 171 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 760 |
| | $ | 710 |
| | $ | 684 |
| | $ | 726 |
|
Property, plant and equipment, net | 6,460 |
| | 6,001 |
| | 5,571 |
| | 5,162 |
|
Total assets | 8,299 |
| | 7,832 |
| | 7,335 |
| | 6,908 |
|
Current liabilities | 628 |
| | 550 |
| | 596 |
| | 455 |
|
Long-term debt | 2,704 |
| | 2,521 |
| | 2,333 |
| | 2,340 |
|
Shareholder's equity | 2,740 |
| | 2,533 |
| | 2,300 |
| | 2,240 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above. |
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 1,332 |
| | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| | $ | 1,282 |
|
Operating income | 190 |
| | 229 |
| | 50 |
| | 165 |
| | 207 |
|
Net income (loss) | 120 |
| | 121 |
| | (9 | ) | | 76 |
| | 104 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 336 |
| | $ | 325 |
| | $ | 370 |
| | $ | 388 |
|
Property, plant and equipment, net | 3,821 |
| | 3,579 |
| | 3,273 |
| | 3,070 |
|
Total assets | 4,588 |
| | 4,357 |
| | 4,153 |
| | 3,969 |
|
Current liabilities | 375 |
| | 547 |
| | 381 |
| | 564 |
|
Long-term debt | 1,403 |
| | 1,217 |
| | 1,221 |
| | 1,061 |
|
Shareholder's equity | 1,509 |
| | 1,335 |
| | 1,326 |
| | 1,237 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above. |
ACE
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 1,236 |
| | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| | $ | 1,210 |
|
Operating income | 149 |
| | 157 |
| | 7 |
| | 134 |
| | 137 |
|
Net income (loss) | 75 |
| | 77 |
| | (42 | ) | | 40 |
| | 46 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 240 |
| | $ | 258 |
| | $ | 399 |
| | $ | 546 |
|
Property, plant and equipment, net | 2,966 |
| | 2,706 |
| | 2,521 |
| | 2,322 |
|
Total assets | 3,699 |
| | 3,445 |
| | 3,457 |
| | $ | 3,387 |
|
Current liabilities | 422 |
| | 619 |
| | 320 |
| | $ | 297 |
|
Long-term debt | 1,170 |
| | 840 |
| | 1,120 |
| | 1,153 |
|
Shareholder's equity | 1,126 |
| | 1,043 |
| | 1,034 |
| | 1,000 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above. |
|
| |
Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has twelve reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 - Significant Accounting Policies and Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations 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.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2018 compared to the same period in 2017 and December 31, 2017 compared to the same period in 2016. For additional information regarding the financial results for the years ended December 31, 2018, 2017 and 2016 see the discussions of Results of Operations by Registrant.
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Exelon | $ | 2,010 |
| | $ | 3,786 |
| | $ | (1,776 | ) | | $ | 1,121 |
| | $ | 2,665 |
|
Generation | 370 |
| | 2,710 |
| | (2,340 | ) | | 483 |
| | 2,227 |
|
ComEd | 664 |
| | 567 |
| | 97 |
| | 378 |
| | 189 |
|
PECO | 460 |
| | 434 |
| | 26 |
| | 438 |
| | (4 | ) |
BGE | 313 |
| | 307 |
| | 6 |
| | 286 |
| | 21 |
|
Pepco | 210 |
| | 205 |
| | 5 |
| | 42 |
| | 163 |
|
DPL | 120 |
| | 121 |
| | (1 | ) | | (9 | ) | | 130 |
|
ACE | 75 |
| | 77 |
| | (2 | ) | | (42 | ) | | 119 |
|
Other(b) | (195 | ) | | (594 | ) | | 399 |
| | (422 | ) | | (172 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to March 23, |
| 2018 | | 2017 | | | 2016 | | | 2016 |
PHI(a) | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
__________
| |
(a) | Includes the consolidated results of Pepco, DPL and ACE. |
| |
(b) | Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities. |
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017. Net income attributable to common shareholdersdecreased by $1,776 million and diluted earnings per average common share decreased to $2.07 in 2018 from $3.99 in 2017 primarily due to:
Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;
The gain associated with the FitzPatrick acquisition in 2017;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017;
Long-lived asset impairments of certain merchant wind assets in West Texas; and
Increased storm costs at PECO and BGE.
The decreases were partially offset by;
The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a ratable basis over three-year periodsresult of the TCJA at Generation;
Net realized gains on NDT funds;
The gain on the settlement of a long-term gas supply agreement;
Decreased nuclear outage days;
Increased electric distribution and energy efficiency formula rate earnings at ComEd;
Regulatory rate increases at PECO, BGE and PHI;
The impact of favorable weather at PECO, DPL and ACE; and
The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The decrease in diluted earnings per share was also due to the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Net income attributable to common shareholdersincreased by $2,665 million and diluted earnings per average common share increased to $3.99 in 2017 from $1.21 in 2016 primarily due to:
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;
Higher net unrealized and realized gains on NDT funds;
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices;
Decreased nuclear outage days;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment in 2016;
Increased electric distribution and transmission formula rate earnings at ComEd;
Regulatory rate increases at BGE and PHI; and
Penalties and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange position in 2016.
The increases were partially offset by;
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility;
Increased mark-to-market losses;
The impact of unfavorable weather at ComEd, PECO, DPL and ACE; and
The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The net increase in diluted earnings per share from the items listed above was partially offset by the impact of the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to reduceenhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the financialongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2018 as compared to 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
(All amounts after tax; in millions, except per share amounts) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 2,010 |
| | $ | 2.07 |
| | $ | 3,786 |
| | $ | 3.99 |
| | $ | 1,121 |
| | $ | 1.21 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $89, $68 and $18, respectively) | 252 |
| | 0.26 |
| | 107 |
| | 0.11 |
| | 24 |
| | 0.03 |
|
Unrealized Losses (Gains) Related to NDT Funds(b) (net of taxes of $289, $286 and $112, respectively) | 337 |
| | 0.35 |
| | (318 | ) | | (0.34 | ) | | (118 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0, $22 and $22, respectively) | — |
| | — |
| | 34 |
| | 0.04 |
| | 35 |
| | 0.04 |
|
Merger and Integration Costs(d) (net of taxes of $2, $25 and $50, respectively) | 3 |
| | — |
| | 40 |
| | 0.04 |
| | 114 |
| | 0.12 |
|
Merger Commitments(e) (net of taxes of $0, $137 and $126, respectively) | — |
| | — |
| | (137 | ) | | (0.14 | ) | | 437 |
| | 0.47 |
|
Long-Lived Asset Impairments(f) (net of taxes of $13, $204 and $68, respectively) | 35 |
| | 0.04 |
| | 321 |
| | 0.34 |
| | 103 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $181, $134 and $273, respectively) | 512 |
| | 0.53 |
| | 207 |
| | 0.22 |
| | 432 |
| | 0.47 |
|
Cost Management Program(h) (net of taxes of $16, $21 and $21, respectively) | 48 |
| | 0.05 |
| | 34 |
| | 0.04 |
| | 34 |
| | 0.04 |
|
Annual Asset Retirement Obligation Update(i) (net of taxes of $7, $1 and $13, respectively) | 20 |
| | 0.02 |
| | (2 | ) | | — |
| | (75 | ) | | (0.08 | ) |
Vacation Policy Change(j) (net of taxes of $0, $21 and $0, respectively) | — |
| | — |
| | (33 | ) | | (0.03 | ) | | — |
| | — |
|
Change in Environmental Liabilities (net of taxes of $0, $17 and $0, respectively) | (1 | ) | | — |
| | 27 |
| | 0.03 |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0, $0 and $0, respectively) | — |
| | — |
| | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Gain on Deconsolidation of Business(l) (net of taxes of $0, $83 and $0, respectively) | — |
| | — |
| | (130 | ) | | (0.14 | ) | | — |
| | — |
|
Gain on Contract Settlement(m) (net of taxes of $20, $0 and $0, respectively) | (55 | ) | | (0.06 | ) | | — |
| | — |
| | — |
| | — |
|
Like-Kind Exchange Tax Position(n) (net of taxes of $0, $66 and $61, respectively) | — |
| | — |
| | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Curtailment of Generation Growth and Development Activities(o) (net of taxes of $0, $0 and $35, respectively) | — |
| | — |
| | — |
| | — |
| | 57 |
| | 0.06 |
|
Reassessment of Deferred Income Taxes(p) (entire amount represents tax expense) | (22 | ) | | (0.02 | ) | | (1,299 | ) | | (1.37 | ) | | 10 |
| | 0.01 |
|
Tax Settlements(q) (net of taxes of $0, $1 and $0, respectively) | — |
| | — |
| | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Noncontrolling Interests(r) (net of taxes of $24, $24 and $9, respectively) | (113 | ) | | (0.12 | ) | | 114 |
| | 0.12 |
| | 102 |
| | 0.11 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 3,026 |
| | $ | 3.12 |
| | $ | 2,487 |
| | $ | 2.62 |
| | $ | 2,475 |
| | $ | 2.67 |
|
__________
Note:
Unless otherwise noted, the income tax impact of market price volatility. Generationeach reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is exposedbased on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to commodity price riskNDT funds, the marginal statutory income tax rates for 2018, 2017 and 2016 ranged from 26.0 percent to 29.0 percent, 39.0 percent to 41.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 46.2 percent, 47.4 percent and 48.7 percent for the years ended December 31, 2018, 2017 and 2016, respectively.
| |
(a) | Reflects the impact of net losses on economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information related to hedging activities. |
| |
(b) | Reflects the impact of net unrealized gains and losses on Generation’s NDT funds for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact. |
| |
(c) | Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions. |
| |
(d) | Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e) | Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions. |
| |
(f) | In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation. |
| |
(g) | In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. |
| |
(h) | Primarily represents severance and reorganization costs related to a cost management program. |
| |
(i) | For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property. |
| |
(j) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(k) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
| |
(l) | Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. |
| |
(m) | Represents the gain on the settlement of a long-term gas supply agreement at Generation. |
| |
(n) | Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position. |
| |
(o) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(p) | Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment. |
| |
(q) | Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests. |
| |
(r) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG. |
Significant 2018 Transactions and Recent Developments
Regulatory Implications of the Tax Cuts and Jobs Act (TCJA)
The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Utility Distribution Base Rate Case Proceedings
|
| | | | | | | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
Pepco - District of Columbia (Electric) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
DPL - Maryland (Electric) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Pending Distribution Base Rate Case Proceedings
|
| | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | | Requested ROE | Expected Approval Timing |
ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019 |
Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
|
| | | | | | | | | | | | | | |
Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase) | | Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) | | 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
Pepco | 6 |
| 2 |
| 8 |
| | 7.82 | % | 10.50 | % |
DPL | 14 |
| 13 |
| 27 |
| | 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
| | 8.02 | % | 10.50 | % |
__________
| |
(a) | The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted. |
| |
(b) | The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and equity return on transmission rate bases. |
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included
an approximately $20 million reduction as a result of the tax savings associated with the unhedgedTCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle and permanently ceased generation operations in September 2018. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committed to operate through May 2019. As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2019 due to the early retirement decisions.
|
| | | | | | | | |
| | Actual | | Projected(a) |
Income statement expense (pre-tax) | | 2018 | | 2019 |
Depreciation and Amortization(b) | | | | |
Accelerated depreciation(c) | | $ | 539 |
| | $ | 230 |
|
Accelerated nuclear fuel amortization | | 57 |
| | 5 |
|
Operating and maintenance(d) | | 32 |
| | 5 |
|
Total | | $ | 628 |
| | $ | 240 |
|
_________
| |
(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
| |
(b) | Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(c) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(d) | Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments. |
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for,
and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 4 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
The ISO-NE announced that it would take a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. On January 4, 2019, Generation notified ISO–NE that it will participate in the Forward Capacity Market auction for the 2022 – 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022–2023 capacity commitment period. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension Plan Merger
Effective January 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial
losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.
Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the twelve months ended December 31, 2018 are presented below:
|
| | | | | | | | | | |
| | | (in millions) |
| Customer Outages | | Incremental Operating & Maintenance | | Incremental Capital Expenditures |
Exelon | 1,727,000 |
| | $ | 88 |
| (b) | $ | 85 |
|
PECO | 750,000 |
| | 53 |
| | 34 |
|
BGE | 425,000 |
| | 31 |
| | 16 |
|
PHI(a) | 552,000 |
| | 4 |
| (b) | 35 |
|
Pepco | 182,000 |
| | 2 |
| (b) | 4 |
|
DPL | 138,000 |
| | 2 |
| (b) | 4 |
|
ACE | 232,000 |
| | — |
| (b) | 27 |
|
________
| |
(a) | PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE. |
| |
(b) | Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21 million, respectively. |
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were assumed by Brookfield on the closing date.
Exelon’s Strategy and Outlook for 2019 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths 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:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity portfolio.generation strategy is to pursue opportunities that provide stable revenues and generation to load matching to reduce earnings volatility. Generation enters into non-derivativeleverages its energy generation portfolio to deliver energy to both wholesale and derivative contracts, including financially-settled swaps, futures contractsretail customers. Generation’s customer-facing activities foster development and swap options,delivery of other innovative energy-related products and physical optionsservices for its customers. Generation operates in well-developed energy markets and physical forward contracts, all with credit-approved counterparties,employs an integrated hedging strategy to hedge this anticipated exposure. Generation has hedges in place that significantly mitigate this risk for 2018 and 2019. However, Generation is exposed to relatively greatermanage commodity price riskvolatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the subsequent years with respectmarket, solutions to which Exelon is actively pursuing in a larger portionvariety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018. Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger enhances Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $29 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $16 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by
increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its electricitygeneration assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1.0 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
For additional information regarding the Registrants' liquidity for the year ended December 31, 2018, see Liquidity and Capital Resources discussion below.
Project Financing
Project financing is currently unhedged. Asused to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities of $0.2 billion as of December 31, 2017,2018. See Note 13 — Debt and Credit Agreements of the percentageCombined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of expected generation hedgedthese regulatory proceedings impact the Utility Registrants’ current and future results
of operations, cash flows and financial positions. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is 85%-88%, 55%-58%increasing natural gas supply and 26%-29% for 2018, 2019,reserves, which places downward pressure on natural gas prices and, 2020 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 astherefore, on wholesale and retail salespower prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power optionssystem and swaps. Generationevaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be proactivean active participant in using hedging strategiesthese proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to mitigate commodity price riskMitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in subsequent years as well.a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
Generation procures oilOn January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and natural gas through long-termanother seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and short-term contractsIllinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and 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,capacity sold in the FERC-jurisdictional markets, and contracted fuel fabrication services. The supply markets for uranium concentratestherefore, are no different than other renewable support programs like the PTC and certain nuclear fuel services, coal, oil and natural gas areRPS programs that have generally not been subject to price fluctuationsa MOPR. However, if successful, for Generation’s facilities in PJM and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to creditNYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk related toof not clearing in future capacity auctions and thus no longer receiving capacity revenues during the potential non-performancerespective ZEC programs. Any mitigation of counterparties to deliver the contracted commodity or service at the
contracted prices. Approximately 59% of Generation’s uranium concentrate requirements from 2018 through 2022 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 counterpartiesgenerating resources could have a material adverseeffect on Exelon’s and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the New Jersey ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second
alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s results of operations, cash flowsfinancial statements.
Potential DOE Order Pursuant to Defense Production Act and financial positions.Federal Power Act
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow themDOE is considering an Order directing ISOs, for 24 months, to recover procurement costspurchase electric energy or generation capacity from retail customers.
Environmental Legislativea designated list of coal and Regulatory Developments
Exelon was actively involved innuclear generation facilities. Based on a draft memorandum, the Obama Administration’s developmentOrder would be pursuant to DOE's authorities under the Defense Production Act and implementation of environmental regulations for the electric industry, in pursuit of its business strategy to provide reliable, clean, affordableFederal Power Act, and innovative energy products. These efforts have most frequently involved air, waterwould forestall any further actions towards retiring, decommissioning, or deactivating coal and waste controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issuednuclear facilities during the Obama Administration, withterm of the expectationOrder. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the Administrationunderlying economic and regulatory issues are complex and will seek repeal or significant revisiontake time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of these rules. Under these EOs, each executive agency is required to evaluate existing regulationslocation-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard 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. 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. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participatebe an active
participant in these proceedings but cannot predict the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP infinal outcome or its entirety, basedpotential financial impact, if any, on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. The EPA has also indicated its intent to issue an advance notice of proposed rulemaking to solicit information on systems of emission reduction that are in accord with the Agency’s proposed revised legal interpretation; namely, only by regulating emission reductions that can be implemented at and to individual sources.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainmentExelon or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.Generation.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1.BUSINESS, "Global Climate Change" for further discussion.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental agency to which the permit program has been delegated and must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such permits after being granted an administrative extension. Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that primarily regulate water usage.
Section 316(b) of the Clean Water Act
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All 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 recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Mountain Creek, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities and Salem.
On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability could be called into question. However, the potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors, such as those that would make cooling towers infeasible.
Pursuant to discussions with the NJDEP in 2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease generation operations at Oyster Creek before the expiration of its operating license in 2029. On September 17, 2018, Oyster Creek permanently ceased generation operations, and its cooling water intake system is no longer subject to Section 316(b). See Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information about the sale and decommissioning of Oyster Creek.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved (i.e., the requirement most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to determine the best technology available in the next permit renewal cycles.
Salem
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be material and could adversely impact the economic competitiveness of this facility.
Solid and Hazardous Waste
CERCLA provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at sites, most of which are listed by the EPA on the National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state oversight prior to listing on the NPL. Various states, including Delaware, Illinois, Maryland, New Jersey and Pennsylvania and the District of Columbia have also enacted statutes that contain provisions substantially similar to CERCLA. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state agencies and/or other responsible parties under CERCLA and RCRA with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and hazardous waste regulation and legislation.
Environmental Remediation
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the MGP sites through a provision within customer rates. BGE, ACE, Pepco and DPL do not have material contingent liabilities relating to MGP sites. The amount to be expended in 2019 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $46 million, consisting of $36 million, $6 million and $4 million at ComEd, PECO and BGE respectively. The Utility Registrants also have contingent liabilities for
environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2018, the Utility Registrants have established appropriate contingent liabilities for environmental remediation requirements.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws.
In addition, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ Consolidated Financial Statements.
Global Climate Change
Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets). Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. As of December 31, 2018, fossil fuel generation represented approximately 29% of Exelon's owned generating capacity, while fossil fuel-fired generation during 2018 represented less than 11% of Exelon's overall generation on a MWh basis. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in motor vehicles. Exelon facilities and operations are subject to the global impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK FACTORS for information regarding the market and financial, regulatory and legislative, and operational risks associated with climate change.
Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
International Climate Change Agreements. At the international level, the United States is a Party to the United Nations Framework Convention on Climate Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on December 12, 2015, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to withdraw the U.S. from the Paris Agreement, but no formal action has been initiated.
Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such legislation is adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively impact the value of Exelon’s low-carbon fleet.
Under the Obama Administration, the EPA proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are currently being litigated. Under the Trump Administration, on October
16, 2017 the EPA proposed to repeal the CPP on the basis that the new Administration believed that the CPP rule went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
Given litigation uncertainty and the absence of a final ACE rule, Exelon and Generation cannot at this time predict the impacts of regulation of existing power plants, or individual state responses to developments related to final resolution of the CPP and ACE regulations, or how developments will impact their future financial statements.
Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas Initiative (RGGI), which is in the process of strengthening its requirements. The program requires most fossil fuel-fired power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold these allowances.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these, besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a competitive advantage for Exelon depends on resolution of the CPP and ACE regulations and associated current or future litigation at the federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of RPS requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. Exelon's utilities comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits (e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy resources. New York, Illinois and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Generation and our utilities operate are considering similar programs.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
Executive Officers of the Registrants as of February 8, 2019
Exelon
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Crane, Christopher M. | | 60 |
| | Chief Executive Officer, Exelon; | | 2012 - Present |
| | | | Chairman, ComEd, PECO & BGE | | 2012 - Present |
| | | | Chairman, PHI | | 2016 - Present |
| | | | President, Exelon | | 2008 - Present |
| | | | President, Generation | | 2008 - 2013 |
| | | | | | |
Cornew, Kenneth W. | | 53 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pramaggiore, Anne R. | | 60 |
| | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | | 2018 - Present |
| | | | Chief Executive Officer, ComEd | | 2012 - 2018 |
| | | | President, ComEd | | 2009 - 2018 |
| | | | | | |
Dominguez, Joseph | | 56 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
Butler, Calvin G. | | 49 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Velazquez, David M. | | 59 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | | | |
Von Hoene Jr., William A. | | 65 |
| | Senior Executive Vice President and Chief Strategy Officer, Exelon | | 2012 - Present |
| | | | | | |
Nigro, Joseph | | 54 |
| | Senior Executive Vice President and Chief Financial Officer, Exelon | | 2018 - Present |
| | | | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2013 - 2018 |
| | | | | | |
Aliabadi, Paymon | | 56 |
| | Executive Vice President and Chief Risk Officer, Exelon | | 2013 - Present |
| | | | Managing Director, Gleam Capital Management | | 2012 - 2013 |
| | | | | | |
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Souza, Fabian E. | | 48 |
| | Senior Vice President and Corporate Controller, Exelon | | 2018 - Present |
| | | | Senior Vice President and Deputy Controller, Exelon | | 2017 - 2018 |
| | | | Vice President, Controller and Chief Accounting Officer, The AES Corporation | | 2015 - 2017 |
| | | | Vice President, Internal Audit and Advisory Services, The AES Corporation | | 2014 - 2015 |
| | | | Deputy Corporate Controller, The AES Corporation | | 2014 - 2014 |
| | | | Assistant Corporate Controller, Global Controllership, The AES Corporation | | 2013 - 2014 |
| | | | Controller, Global Utilities, The AES Corporation | | 2011 - 2013 |
Generation
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Cornew, Kenneth W. | | 53 |
| | Senior Executive Vice President and Chief Commercial Officer, Exelon; | | 2013 - Present |
| | | | President and CEO, Generation | | 2013 - Present |
| | | | Executive Vice President and Chief Commercial Officer, Exelon | | 2012 - 2013 |
| | | | President and Chief Executive Officer, Constellation | | 2012 - 2013 |
| | | | | | |
Pacilio, Michael J. | | 58 |
| | Executive Vice President and Chief Operating Officer, Exelon Generation | | 2015 - Present |
| | | | President, Exelon Nuclear; Senior Vice President | | 2010 - 2015 |
| | | | and Chief Nuclear Officer, Generation | | |
| | | | | | |
Hanson, Bryan C | | 53 |
| | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation | | 2015 - Present |
| | | | | | |
McHugh, James | | 47 |
| | Executive Vice President, Exelon; Chief Executive Officer, Constellation | | 2018 - Present |
| | | | Senior Vice President, Portfolio Management & Strategy, Constellation | | 2016 - 2018 |
| | | | Vice President, Portfolio Management, Constellation | | 2012 - 2016 |
| | | | | | |
Barnes, John | | 55 |
| | Senior Vice President, Generation; President, Exelon Power | | 2018 - Present |
| | | | Senior Vice President, Generation, Senior Vice President and Chief Operating Officer, Exelon Power | | 2012 - 2018 |
| | | | | | |
Wright, Bryan P. | | 52 |
| | Senior Vice President and Chief Financial Officer, Generation | | 2013 - Present |
| | | | Senior Vice President, Corporate Finance, Exelon | | 2012 - 2013 |
| | | | | | |
Bauer, Matthew N. | | 42 |
| | Vice President and Controller, Generation | | 2016 - Present |
| | | | Vice President and Controller, BGE | | 2014 - 2016 |
| | | | Vice President of Power Finance, Exelon Power | | 2012 - 2014 |
ComEd
|
| | | | | | | |
Name | | Age |
| | Position | | Period |
Dominguez, Joseph | | 56 |
| | Chief Executive Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2015 - 2018 |
| | | | Senior Vice President, Governmental & Regulatory Affairs and Public Policy, Exelon | | 2012 - 2015 |
| | | | | | |
Donnelly, Terence R. | | 58 |
| | President and Chief Operating Officer, ComEd | | 2018 - Present |
| | | | Executive Vice President and Chief Operating Officer, ComEd | | 2012 - 2018 |
| | | | | | |
Jones, Jeanne M. | | 39 |
| | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | | 2018 - Present |
| | | | Vice President, Finance, Exelon Nuclear | | 2014 - 2018 |
| | | | Director, Finance, Exelon Nuclear | | 2013 - 2014 |
| | | | | | |
Park, Jane | | 46 |
| | Senior Vice President, Customer Operations, ComEd | | 2018 - Present |
| | | | Vice President, Regulatory Policy & Strategy, ComEd | | 2016 - 2018 |
| | | | Director, Business Strategy & Technology, ComEd | | 2014 - 2016 |
| | | | Chief of Staff to President and Chief Executive Officer, ComEd | | 2012 - 2014 |
| | | | | | |
Gomez, Veronica | | 49 |
| | Senior Vice President, Regulatory and Energy Policy and General Counsel, ComEd | | 2017 - Present |
| | | | Vice President and Deputy General Counsel, Litigation, Exelon | | 2012 - 2017 |
| | | | | | |
Marquez Jr., Fidel | | 57 |
| | Senior Vice President, Governmental and External Affairs, ComEd | | 2012 - Present |
| | | | | | |
McGuire, Timothy M. | | 60 |
| | Senior Vice President, Distribution Operations, ComEd | | 2016 - Present |
| | | | Vice President, Transmission and Substations, ComEd | | 2010 - 2016 |
| | | | | | |
Kozel, Gerald J. | | 46 |
| | Vice President, Controller, ComEd | | 2013 - Present |
| | | | Assistant Corporate Controller, Exelon | | 2012 - 2013 |
PECO
|
| | | | | | | |
Name | | Age | | Position | | Period |
Innocenzo, Michael A. | | 53 |
| | President and Chief Executive Officer, PECO | | 2018 - Present |
| | | | Senior Vice President and Chief Operations Officer, PECO | | 2012 - 2018 |
| | | | | | |
McDonald, John | | 61 |
| | Senior Vice President and Chief Operations Officer, PECO | | 2018 - Present |
| | | | Vice President, Integration, Pepco Holdings | | 2016 - 2018 |
| | | | Vice President, Technical Services | | 2006 - 2016 |
Stefani, Robert J. | | 44 |
| | Senior Vice President, Chief Financial Officer and Treasurer, PECO | | 2018 - Present |
| | | | Vice President, Corporate Development, Exelon | | 2015 - 2018 |
| | | | Director, Corporate Development, Exelon | | 2012 - 2015 |
| | | | | | |
Murphy, Elizabeth A. | | 59 |
| | Senior Vice President, Governmental and External Affairs, PECO | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, PECO | | 2012 - 2016 |
| | | | | | |
Webster Jr., Richard G. | | 57 |
| | Vice President, Regulatory Policy and Strategy, PECO | | 2012 - Present |
| | | | | | |
Feldhake, Lauren | | 53 |
| | Vice President, Customer Operations, PECO | | 2017 - Present |
| | | | Director, Customer Care, PECO | | 2014 - 2017 |
| | | | Director, Customer Financial Operations, PECO | | 2009 - 2014 |
| | | | | | |
Diaz Jr., Romulo L. | | 72 |
| | Vice President and General Counsel, PECO | | 2012 - Present |
| | | | | | |
Bailey, Scott A. | | 42 |
| | Vice President and Controller, PECO | | 2012 - Present |
BGE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Butler, Calvin G. | | 49 |
| | Chief Executive Officer, BGE | | 2014 - Present |
| | | | Senior Vice President, Regulatory and External Affairs, BGE | | 2013 - 2014 |
| | | | Senior Vice President, Corporate Affairs, Exelon | | 2011 - 2013 |
| | | | | | |
Woerner, Stephen J. | | 51 |
| | President, BGE | | 2014 - Present |
| | | | Chief Operating Officer, BGE | | 2012 - Present |
| | | | Senior Vice President, BGE | | 2009 - 2014 |
| | | | | | |
Vahos, David M. | | 46 |
| | Senior Vice President, Chief Financial Officer and Treasurer, BGE | | 2016 - Present |
| | | | Vice President, Chief Financial Officer and Treasurer, BGE | | 2014 - 2016 |
| | | | Vice President and Controller, BGE | | 2012 - 2014 |
| | | | | | |
Núñez, Alexander G. | | 47 |
| | Senior Vice President, Regulatory and External Affairs, BGE | | 2016 - Present |
| | | | Vice President, Governmental and External Affairs, BGE | | 2013 - 2016 |
| | | | Director, State Affairs, BGE | | 2012 - 2013 |
| | | | | | |
Case, Mark D. | | 57 |
| | Vice President, Strategy and Regulatory Affairs, BGE | | 2012 - Present |
| | | | | | |
Oddoye, Rodney | | 42 |
| | Vice President, Customer Operations, BGE | | 2018 - Present |
| | | | Director, Northeast Regional Electric Operations, BGE | | 2016 - 2018 |
| | | | Director, Financial Operations, BGE | | 2015 - 2016 |
| | | | Manager, Distribution Operations, BGE | | 2013 - 2015 |
| | | | | | |
Corse, John | | 58 |
| | Vice President and General Counsel, BGE | | 2018 - Present |
| | | | Associate General Counsel, Exelon | | 2012 - 2018 |
| | | | | | |
Holmes, Andrew W. | | 50 |
| | Vice President and Controller, BGE | | 2016 - Present |
| | | | Director, Generation Accounting, Exelon | | 2013 - 2016 |
| | | | Director, Derivatives and Technical Accounting, Exelon | | 2008 - 2013 |
PHI, Pepco, DPL and ACE
|
| | | | | | | |
Name | | Age | | Position | | Period |
Velazquez, David M. | | 59 |
| | President and Chief Executive Officer, PHI | | 2016 - Present |
| | | | Executive Vice President, Pepco Holdings, Inc. | | 2009 - 2016 |
| | | | President and Chief Executive Officer, Pepco, DPL and ACE | | 2009 - Present |
| | | | | | |
Anthony, J. Tyler | | 54 |
| | Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Senior Vice President, Distribution Operations, ComEd | | 2010 - 2016 |
| | | | | | |
Barnett, Phillip S. | | 55 |
| | Senior Vice President, Chief Financial Officer and Treasurer PHI, Pepco, DPL and ACE | | 2018 - Present |
| | | | Senior Vice President and Chief Financial Officer, PECO | | 2007 - 2018 |
| | | | Treasurer, PECO | | 2012 - 2018 |
| | | | | | |
Lavinson, Melissa | | 49 |
| | Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL and ACE | | 2018 - Present |
| | | | Vice President, Federal Affairs and Policy and Chief Sustainability Officer, PG&E Corporation | | 2015 - 2018 |
| | | | Vice President, Federal Affairs, PG&E Corporation | | 2012 - 2015 |
| | | | | | |
Stark, Wendy E. | | 46 |
| | Senior Vice President, Legal and Regulatory Strategy and General Counsel, PHI, Pepco, DPL and ACE | | 2019 - Present |
| | | | Vice President and General Counsel, PHI, Pepco DPL and ACE | | 2016 - 2018 |
| | | | Deputy General Counsel, Pepco Holdings, Inc. | | 2012 - Present |
| | | | | | |
McGowan, Kevin M. | | 57 |
| | Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Vice President, Regulatory Affairs, Pepco Holdings, Inc. | | 2012 - 2016 |
| | | | | | |
Aiken, Robert | | 52 |
| | Vice President and Controller, PHI, Pepco, DPL and ACE | | 2016 - Present |
| | | | Vice President and Controller, Generation | | 2012 - 2016 |
Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond that Registrant’s control. Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC), which comprises officers of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks. The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon Board of Directors and the ComEd, PECO, BGE and PHI Boards of Directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors evaluates risks related to the generation business. The risk factors discussed below could adversely affect one or more of the Registrants’ consolidated financial statements and the market prices of their publicly traded securities. Each of the Registrants has disclosed the known material risks that affect its business at this time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed by a Registrant to be material that could adversely affect its performance or financial condition in the future.
Exelon's consolidated financial statements are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power into competitive energy markets with a concentration in select regions
and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United States. Factors that affect the consolidated financial statements of the Registrants fall primarily under the following categories, all of which are discussed in further detail below:
Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going competition in the retail channel and (5) emerging technologies and business models.
Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that govern competitive markets and utility regulatory business model cost recovery, tax policy, zero emission credit programs and environmental policy. In particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced significantly by state regulation and regulatory proceedings.
Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the reliability, safety and efficiency of their energy delivery systems.
A discussion of each of these risk categories and other risk factors is included below.
Market and Financial Factors
Generation is exposed to depressed prices in the wholesale and retail power markets, which could negatively affect its consolidated financial statements (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants such as Exelon's nuclear plants.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.
Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s consolidated financial statements and such impacts could be emphasized given Generation’s concentration of base-load electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect Exelon’s and Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Exelon's and Generation's result of operations through accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning costs, which can be offset in whole or in part by reduced operating and maintenance expenses. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
In addition to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and could negatively affect its results of operations (Exelon and Generation).
Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated to purchase energy or fuel from Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent of amounts, if any, already paid to the counterparties. In the spot markets, Generation is exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs, the purpose of which is to spread such risk across all market participants. Generation is also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry, including technologies related to energy generation, distribution and consumption (All Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable energy technologies, energy efficiency, distributed generation and energy
storage devices. Such developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our electric system power supply and transmission and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could materially affect the Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, and increased capital expenditures, as well as potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase Generation’s funding requirements to decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the costs and funding requirements of the obligations related to the pension and OPEB plans. If future increases in pension and other postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility Registrants' customers, the consolidated financial statements of the Utility Registrants could be negatively affected. Ultimately, if the Registrants are unable to manage the investments within the NDT funds and benefit plan assets and are unable to manage the related benefit plan liabilities and the related asset retirement obligations, their consolidated financial statements could be negatively impacted.
Unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets; each could negatively impact the Registrants’ consolidated financial statements (All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their financial commitments and short-term liquidity needs if internal funds are not available from the Registrants’ respective operations. Disruptions in the capital and credit markets in the United States or abroad could adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their funding commitments. Those banks may not be able to meet their funding commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests from the Registrants and other borrowers within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, changes to Generation’s hedging strategy in order to reduce collateral posting requirements, or a reduction in dividend payments or other discretionary uses of cash.
In addition, the Registrants have exposure to worldwide financial markets, including Europe, Canada and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2018, approximately 19%, or $1.8 billion, 19%, or $1.8 billion, and 18%, or $1.7 billion of the Registrants’ available credit facilities were with European, Canadian and Asian banks, respectively. The credit facilities include $9.7 billion (including bilateral credit facilities and credit facilities for project
finance) in aggregate total commitments of which $8.0 billion was available as of December 31, 2018. As of December 31, 2018, there were no borrowings under Generation's bilateral credit facilities. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be adversely affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts, which could have a material adverse effect on Exelon’s and Generation’s consolidated financial statements.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including (1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices. In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Generation could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in general, or Generation in particular, has deteriorated. Changes in ratings methodologies by the credit rating agencies could also have a negative impact on the ratings of Generation. Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific financings to enter into bankruptcy proceedings. The impact of bankruptcy on such arrangements may be a significant assumption in performing impairment assessments of the project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's and DPL's natural gas procurement contracts contain collateral provisions that are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE and DPL, with respect to their natural gas supply contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. Given the relationship to forward market prices, contract collateral requirements can be volatile. In addition, if the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.
A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures (commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on the Registrants’ cash flows.
Generation’s financial performance could be negatively affected by price volatility, availability and other risk factors associated with the procurement of nuclear and fossil fuel (Exelon and Generation).
Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the consolidated financial statements for Generation.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement and other commodity trading activities expose Generation to risks of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its business or consolidated financial statements.
Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its power portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its power portfolio or effectively address the changes in the wholesale power markets.
Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could impact the Registrants’ consolidated financial statements. (All Registrants).
Corporate Tax Reform. On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA, further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future consolidated financial statements.
The Utility Registrants have made their best estimate regarding the probability and timing of settlements of net regulatory liabilities established pursuant to the TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could have a material impact on the Utility Registrants’ future consolidated financial statements.
Tax reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates, including increases in the cost of purchased power and increases in natural gas prices for the Utility Registrants, and the impact of economic downturns could lead to greater expense for uncollectible customer balances. Additionally, increased rates could lead to decreased volumes delivered. Both of these factors could decrease Generation’s and the Utility Registrants' results from operations, cash flows or financial positions (All Registrants).
The impacts of economic downturns on the Utility Registrants' customers, such as unemployment for residential customers and less demand for products and services provided by commercial and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible customer balances', which would negatively affect the Utility Registrants' consolidated financial statements. Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances which could negatively affect Generation's consolidated financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Utility Registrants' current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s, PECO’s and ACE's costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas could result in declines in customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challenges by the regulators or the Utility Registrants as to the recoverability of these costs could have a material adverse effect in the Registrants’ consolidated financial statements. Also, the Utility Registrants' cash flows could be adversely affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
The effects of weather could impact the Registrants’ consolidated financial statements (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues
at PECO, DPL Delaware and ACE. Due to revenue decoupling, BGE, Pepco and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per customer, regardless of what actual distribution volumes are for a billing period, and are not affected by actual weather with the exception of major storms. Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication systems and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. These extreme conditions could have detrimental effects in the Utility Registrants' consolidated financial statements. First and third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could have an adverse effect by causing Generation to seek additional capacity at a time when wholesale markets are tight or to seek to sell excess capacity at a time when markets are weak.
Certain long-lived assets and other assets recorded on the Registrants’ statements of financial position could become impaired, which would result in write-offs of the impaired amounts (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon and Generation have significant balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements. The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered when evaluating long-lived assets for potential impairment. An impairment would require the Registrants to reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and such an impairment could have a material adverse impact in the Registrants’ consolidated financial statements.
As of December 31, 2018, Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in 2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.
Regulatory actions or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, PHI’s, and ComEd’s goodwill, which could be material.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates, Note 6 — Property, Plant and Equipment, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 10 — Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset and goodwill impairments.
Exelon and its subsidiaries at times guarantee the performance of third parties, which could result in substantial costs in the event of non-performance by such third parties. In addition, the Registrants could have rights under agreements which obligate third parties to indemnify the Registrants for various obligations, and the Registrants could incur substantial costs in the event that the applicable Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection with the acquisition and divestiture of assets (All Registrants).
Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries to perform in the event that the third parties do not perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its obligations under these guarantees. Such performance guarantees could have a material impact in the consolidated financial statements of the Registrant. Some of the Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and a Registrant could incur substantial costs to fulfill its obligations under these indemnities and such costs could adversely affect a Registrant’s consolidated financial statements.
Some of the Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations, which could adversely impact that Registrant’s consolidated financial statements. Each of the Utility Registrants has transferred its former generation business to a third party and in each case the transferee may have agreed to assume certain obligations and to indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO and BGE transferred their generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s and BGE's rights and obligations with respect to their former generation businesses. Further, ComEd, PECO and BGE may have entered into agreements with third parties under which the third-party agreed to indemnify ComEd, PECO or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the restructuring. If the third-party, Generation or the transferee of Pepco's, DPL's or ACE’s generation facilities experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims, which could impact that Utility Registrant's consolidated financial statements. In addition, the Utility Registrants may have residual liability under certain laws in connection with their former generation facilities.
Regulatory and Legislative Factors
The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to regulatory and legislative actions that adversely affect their consolidated financial statements. Fundamental changes in regulation or legislation or violation of tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations, cash flows or financial results (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and Generation’s consolidated financial statements are significantly affected by Generation's sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s and the Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power and natural gas to their customers. Similarly, there is risk that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws. Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and operations and could negatively impact their respective consolidated financial statements.
State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information, resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s consolidated financial statements. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Legislative and regulatory efforts in Illinois, New York and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through zero emission credit programs are subject to legal challenges and, if overturned, could negatively impact Exelon’s and Generation’s consolidated financial statements and result in the early retirement of certain of Generation’s nuclear plants.
Generation could be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and functioning of the wholesale markets (Exelon and Generation).
Approximately 63% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are located in the area encompassed by PJM. Generation’s future results of operations will depend on (1) FERC’s continued adherence to and support for, policies that favor the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.
FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s authority to sell at market-based rates and none denying that authority.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin and capital requirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities. Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other type of covered financial entity.
There are some rulemaking proceedings that have not yet been finalized, in particular, proposed rules on position limits that would apply to both Exchange-traded futures contracts and economically-equivalent over-the-counter swaps. Although the company would incur some costs associated with monitoring and compliance with such rules, it does not expect the rules to have a material impact on its business operations.
The Utility Registrants could also be subject to some Dodd-Frank requirements to the extent they were to enter into swaps. However, at this time, management of the Utility Registrants continue to expect that their companies will not be materially affected by Dodd-Frank.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators and advocacy groups are aware of Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased
costs of energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time, complexity and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes and contributions to rate-relief packages.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All Registrants).
The businesses which the Registrants operate are subject to extensive environmental regulation and legislation by local, state and Federal authorities. These laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and water emissions and solid waste disposal. Violations of these emission and disposal requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of property now or formerly owned by the Registrants and of property contaminated by hazardous substances they generate. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation and clean-up. Remediation activities associated with MGP operations conducted by predecessor companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future.
If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and exposure.
In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person could attempt to hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy and subject to appeal, which lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups and various consumers of energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. The proceedings generally have timelines that may not be limited by statute. Decisions are subject to appeal, potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure, and energy efficiency and demand response programs.
In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or franchise agreements. These settlements are subject to regulatory approval.
The Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs or earn an adequate return and could have a material adverse effect in the Utility Registrants' consolidated financial statements. See Note 4 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively affect the consolidated financial statements of Generation and the Utility Registrants (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as smart meters and smart grid, have increased capital expenditures and could significantly impact the Utility Registrants if timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting from the implementation of new energy conservation technologies could lead to a decline in the revenues of Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1. BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.
The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material to Exelon and the Utility Registrants (Exelon and the Utility Registrants).
As of December 31, 2018, Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business. That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting the regulatory accounting criteria could cause significant volatility in future results of operations. See Note 1 — Significant Accounting Policies, Note 4 — Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.
Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address climate change (Exelon and Generation).
Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission
allowance credits. See ITEM 1. BUSINESS — Global Climate Change and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding climate change.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
As a result of the Energy Policy Act of 2005, users, owners and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. As operators of natural gas distribution systems, PECO, BGE and DPL are also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants have large consumer customer bases and as a result could be the subject of public criticism focused on the operability of their assets and infrastructure and quality of their service. Adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and other regulatory authorities, and government officials less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements (e.g. disallowances of costs, lower ROEs). The imposition of any of the foregoing could have a material negative impact on the Registrants' business or consolidated financial statements.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could negatively impact their consolidated financial statements (All Registrants).
The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures, result in lost revenue or restrict existing business activities, any of which could have a material adverse effect in the Registrants’ consolidated financial statements.
Generation could be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations and profitability of its nuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs and significantly affect Generation’s consolidated financial statements. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, such as the one previously considered at Yucca Mountain, Nevada, and the timing of such facility opening, will significantly affect the costs associated with storage of SNF, and the ultimate amounts received from the DOE to reimburse Generation for these costs. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to decommission fully its nuclear units. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF disposal. However, such a fee could be material to Generation's consolidated financial statements. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
Operational Factors
The Registrants’ employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous environments near their operations. As a result, employees, contractors, customers and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure, gas explosions, pole strikes and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact the Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters, such as seismic activity, fires resulting from natural causes such as lightning, extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units. Additionally, natural disasters and other events that have an adverse effect on the economy in general could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. As owner-operators of infrastructure facilities, such as nuclear, fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, the Registrants face a risk that their operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic events could compromise the physical or cyber security of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain, which could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission and distribution assets could be affected, resulting in decreased service levels and increased costs.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower capacity factors increase Generation’s operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation experiences unplanned outages, capacity factors decrease and Generation faces lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation has to shutdown the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy, which could significantly affect Generation’s consolidated financial statements. In addition, closure of generating plants owned by others, or extended interruptions of generating plants or failure of transmission lines, could affect transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed Generation’s resources, including insurance coverage. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by Generation and could have a material adverse effect in Generation’s consolidated financial statements. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy and significantly adversely affect Generation’s consolidated financial statements.
Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site. Claims exceeding that amount are covered through
mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $14.1 billion limit for a single incident.
Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility. Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the NRC-estimated funding levels including scheduled contributions to and earnings on the NDT funds. The NRC funding levels are based upon the assumption that decommissioning will commence after the end of the current licensed life of each unit.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs and Federal and state regulatory requirements. No assurance can be given that the costs of such decommissioning will not substantially exceed such liability, as facts, circumstances or our estimates may change, including changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning activities.
The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is making contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively affected and Exelon’s and Generation’s consolidated financial statements could be significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. Ultimately, if the investments held by Generation’s NDTs are not sufficient to fund the decommissioning of Generation’s nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met. As a result, Generation’s consolidated financial statements could be significantly adversely affected. Additionally, if the pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.
If the expected value in the NDT funds for any nuclear unit subject to the regulatory agreements with the ICC is expected to not exceed the total decommissioning obligation for that unit, the accounting to offset decommissioning-
related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s consolidated financial statements could be material. For the nuclear units subject to the regulatory agreements with the PAPUC, any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s consolidated financial statements could be material. If the accounting to offset decommissioning-related activities is discontinued, any remaining balances in noncurrent payables to affiliates at Generation and ComEd's or PECO’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact in Generation’s Consolidated Statement of Operations and Comprehensive Income.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the interstate electric grid. The license for the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired on September 1, 2014. FERC issued an annual license, effective as of the expiration of the previous license. If FERC does not issue a license prior to the expiration of the annual license, the annual license renews automatically. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license, Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs or could render the project uneconomic and significantly affect Generation’s consolidated financial statements. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by Generation.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility Registrants in transmission and distribution infrastructure projects. These operational systems and infrastructure have been in service for many years. Equipment, even if maintained in accordance with good utility practices, is subject to operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants’ respective consolidated financial statements could be adversely affected if they were unable to effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure of electric or gas systems, generation facilities or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' operating costs, and customers’ and regulators’ opinions of the Utility Registrants are affected by their ability to maintain the availability and reliability of their delivery and operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities, including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas delivery, which could negatively impact related revenues, and increase maintenance and capital expenditures. Equipment or facilities failures can be due to a number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of advanced metering infrastructure, smart grid or other technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems, the Utility Registrants' consolidated financial statements could be negatively impacted. Furthermore, if
any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results could be negatively impacted. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating the operational systems, the Utility Registrants' financial results could also be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory oversight and the Utility Registrants' maintenance and capital expenditures. Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some circumstances involving extended outages affecting large numbers of its customers, and those damages could be material to ComEd’s consolidated financial statements.
The Utility Registrants' respective ability to deliver electricity, their operating costs and their capital expenditures could be negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of electricity usage with consequent effects on operating costs, revenues and results of operations. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission systems through additional capital expenditures.
The electricity transmission facilities of the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the interstate power transmission grid that is operated by PJM RTO. Although PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an adverse impact on the operations of the other utilities, there can be no assurance that service interruptions at other utilities will not cause interruptions in the Utility Registrants’ service areas. If the Utility Registrants were to suffer such a service interruption, it could have a negative impact in their and Exelon’s consolidated financial statements.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in commodities trading. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural gas utility industry associated with protection of sensitive and confidential information, grid infrastructure and other energy infrastructures, and such attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical infrastructure information, sensitive customer, vendor and employee data, trading or other confidential data. The risk of these system-related events and security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant breach were to occur, the reputation of Exelon or another Registrant and its customer supply activities could be adversely affected, customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its subsidiaries could be subject to legal claims, loss of revenues, increased costs, operations shutdown, etc., any of which could contribute to the loss of customers and have a negative impact on the business and/or consolidated financial statements. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. The Utility Registrants' deployment of smart meters throughout their service territories could increase the
risk of damage from an intentional disruption of the system by third parties. In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their business operations and could adversely affect their consolidated financial statements.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ consolidated financial statements (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation, transmission and distribution operations. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their consolidated financial statements could be negatively impacted.
The Registrants could make investments in new business initiatives, including initiatives mandated by regulators, and markets that may not be successful, and acquisitions could not achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties, distributed generation, potential expansion of the existing wholesale gas businesses and entry into liquefied natural gas. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established competitors that increase competition for customers and resources. Additionally, it is possible that FERC, state public utility commissions or others could impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated Smart Grid and utility of the future initiatives and other non-regulatory mandated initiatives. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity and obsolescence of technology. Due to these risks, no assurance can be given that such initiatives will be successful and will not have a material adverse effect in the Utility Registrants' consolidated financial statements.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts which could impact the Registrants’ results of operations (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
|
| |
ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
Generation
The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2018:
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Braidwood | Midwest | Braidwood, IL | 2 |
| | Uranium | Base-load | 2,386 |
| |
Byron | Midwest | Byron, IL | 2 |
| | Uranium | Base-load | 2,347 |
| |
LaSalle | Midwest | Seneca, IL | 2 |
| | Uranium | Base-load | 2,320 |
| |
Dresden | Midwest | Morris, IL | 2 |
| | Uranium | Base-load | 1,845 |
| |
Quad Cities | Midwest | Cordova, IL | 2 |
| 75 |
| Uranium | Base-load | 1,403 |
| (e) |
Clinton | Midwest | Clinton, IL | 1 |
| | Uranium | Base-load | 1,069 |
| |
Michigan Wind 2 | Midwest | Sanilac Co., MI | 50 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Beebe | Midwest | Gratiot Co., MI | 34 |
| 51 |
| Wind | Base-load | 42 |
| (e)(h) |
Michigan Wind 1 | Midwest | Huron Co., MI | 46 |
| 51 |
| Wind | Base-load | 35 |
| (e)(g) |
Harvest 2 | Midwest | Huron Co., MI | 33 |
| 51 |
| Wind | Base-load | 30 |
| (e)(g) |
Harvest | Midwest | Huron Co., MI | 32 |
| 51 |
| Wind | Base-load | 27 |
| (e)(g) |
Beebe 1B | Midwest | Gratiot Co., MI | 21 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Ewington | Midwest | Jackson Co., MN | 10 |
| 99 |
| Wind | Base-load | 20 |
| (e) |
Marshall | Midwest | Lyon Co., MN | 9 |
| 99 |
| Wind | Base-load | 19 |
| (e) |
City Solar | Midwest | Chicago, IL | 1 |
| | Solar | Base-load | 9 |
| |
Solar Ohio | Midwest | Toledo, OH | 2 |
| | Solar | Base-load | 4 |
| |
Blue Breezes | Midwest | Faribault Co., MN | 2 |
| | Wind | Base-load | 3 |
| |
CP Windfarm | Midwest | Faribault Co., MN | 2 |
| 51 |
| Wind | Base-load | 2 |
| (e)(g) |
Southeast Chicago | Midwest | Chicago, IL | 8 |
| | Gas | Peaking | 296 |
| (k) |
Clinton Battery Storage | Midwest | Blanchester, OH | 1 |
| | Energy Storage | Peaking | 10 |
| |
Total Midwest | | | | | | | 11,939 |
| |
| | | | | | | | |
Limerick | Mid-Atlantic | Sanatoga, PA | 2 |
| | Uranium | Base-load | 2,317 |
| |
Peach Bottom | Mid-Atlantic | Delta, PA | 2 |
| 50 |
| Uranium | Base-load | 1,324 |
| (e) |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 2 |
| 42.59 |
| Uranium | Base-load | 1,002 |
| (e) |
Calvert Cliffs | Mid-Atlantic | Lusby, MD | 2 |
| 50.01 |
| Uranium | Base-load | 895 |
| (e)(f) |
Three Mile Island | Mid-Atlantic | Middletown, PA | 1 |
| | Uranium | Base-load | 837 |
| (j) |
Conowingo | Mid-Atlantic | Darlington, MD | 11 |
| | Hydroelectric | Base-load | 572 |
| |
Criterion | Mid-Atlantic | Oakland, MD | 28 |
| 51 |
| Wind | Base-load | 36 |
| (e)(g) |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Fair Wind | Mid-Atlantic | Garrett County, MD | 12 |
| | Wind | Base-load | 30 |
| |
Solar Maryland MC | Mid-Atlantic | Various, MD | 40 |
| | Solar | Base-load | 36 |
| |
Fourmile | Mid-Atlantic | Garrett County, MD | 16 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Solar New Jersey 1 | Mid-Atlantic | Various, NJ | 5 |
| | Solar | Base-load | 18 |
| |
Solar New Jersey 2 | Mid-Atlantic | Various, NJ | 2 |
| | Solar | Base-load | 11 |
| |
Solar Horizons | Mid-Atlantic | Emmitsburg, MD | 1 |
| 51 |
| Solar | Base-load | 8 |
| (e)(g) |
Solar Maryland | Mid-Atlantic | Various, MD | 11 |
| | Solar | Base-load | 8 |
| |
Solar Maryland 2 | Mid-Atlantic | Various, MD | 3 |
| | Solar | Base-load | 8 |
| |
Constellation New Energy | Mid-Atlantic | Gaithersburg, MD | 1 |
| | Solar | Base-load | 5 |
| |
Solar Federal | Mid-Atlantic | Trenton, NJ | 1 |
| | Solar | Base-load | 5 |
| |
Solar New Jersey 3 | Mid-Atlantic | Middle Township, NJ | 5 |
| 51 |
| Solar | Base-load | 1 |
| (e)(g) |
Solar DC | Mid-Atlantic | District of Columbia | 1 |
| | Solar | Base-load | 1 |
| |
Muddy Run | Mid-Atlantic | Drumore, PA | 8 |
| | Hydroelectric | Intermediate | 1,070 |
| |
Eddystone 3, 4 | Mid-Atlantic | Eddystone, PA | 2 |
| | Oil/Gas | Intermediate | 760 |
| |
Perryman | Mid-Atlantic | Aberdeen, MD | 5 |
| | Oil/Gas | Peaking | 404 |
| |
Croydon | Mid-Atlantic | West Bristol, PA | 8 |
| | Oil | Peaking | 391 |
| |
Handsome Lake | Mid-Atlantic | Kennerdell, PA | 5 |
| | Gas | Peaking | 268 |
| |
Notch Cliff | Mid-Atlantic | Baltimore, MD | 8 |
| | Gas | Peaking | 117 |
| (k) |
Westport | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 116 |
| (k) |
Richmond | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 98 |
| |
Gould Street | Mid-Atlantic | Baltimore, MD | 1 |
| | Gas | Peaking | 97 |
| (k) |
Philadelphia Road | Mid-Atlantic | Baltimore, MD | 4 |
| | Oil | Peaking | 61 |
| |
Eddystone | Mid-Atlantic | Eddystone, PA | 4 |
| | Oil | Peaking | 60 |
| |
Fairless Hills | Mid-Atlantic | Fairless Hills, PA | 2 |
| | Landfill Gas | Peaking | 60 |
| (k) |
Delaware | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 56 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Southwark | Mid-Atlantic | Philadelphia, PA | 4 |
| | Oil | Peaking | 52 |
| |
Falls | Mid-Atlantic | Morrisville, PA | 3 |
| | Oil | Peaking | 51 |
| |
Moser | Mid-Atlantic | Lower PottsgroveTwp., PA | 3 |
| | Oil | Peaking | 51 |
| |
Riverside | Mid-Atlantic | Baltimore, MD | 2 |
| | Oil | Peaking | 39 |
| (k)(l) |
Chester | Mid-Atlantic | Chester, PA | 3 |
| | Oil | Peaking | 39 |
| |
Schuylkill | Mid-Atlantic | Philadelphia, PA | 2 |
| | Oil | Peaking | 30 |
| |
Salem | Mid-Atlantic | Lower Alloways Creek Township, NJ | 1 |
| 42.59 |
| Oil | Peaking | 16 |
| (e) |
Pennsbury | Mid-Atlantic | Morrisville, PA | 2 |
| | Landfill Gas | Peaking | 4 |
| (e) |
Bethlehem | Mid-Atlantic | Bethlehem, PA | 1 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Eastern | Mid-Atlantic | Bethlehem, PA | 3 |
| | Landfill Gas | Peaking | 4 |
| (k) |
Total Mid-Atlantic | | | | | | | 10,982 |
| |
| | | | | | | | |
Whitetail | ERCOT | Webb County, TX | 57 |
| 51 |
| Wind | Base-load | 46 |
| (e)(g) |
Sendero | ERCOT | Jim Hogg and Zapata County, TX | 39 |
| 51 |
| Wind | Base-load | 40 |
| (e)(g) |
Constellation Solar Texas | Other | Various, TX | 11 |
| | Solar | Base-load | 13 |
| |
Colorado Bend II | ERCOT | Wharton, TX | 3 |
| | Gas | Intermediate | 1,088 |
| |
Wolf Hollow II | ERCOT | Granbury, TX | 3 |
| | Gas | Intermediate | 1,064 |
| |
Handley 3 | ERCOT | Fort Worth, TX | 1 |
| | Gas | Intermediate | 395 |
| |
Handley 4, 5 | ERCOT | Fort Worth, TX | 2 |
| | Gas | Peaking | 870 |
| |
Total ERCOT | | | | | | | 3,516 |
| |
| | | | | | | | |
Solar Massachusetts | New England | Various, MA | 10 |
| | Solar | Base-load | 7 |
| |
Holyoke Solar | New England | Various, MA | 2 |
| | Solar | Base-load | 5 |
| |
Solar Net Metering | New England | Uxbridge, MA | 1 |
| | Solar | Base-load | 2 |
| |
Solar Connecticut | New England | Various, CT | 1 |
| | Solar | Base-load | 1 |
| |
Mystic 8, 9 | New England | Charlestown, MA | 6 |
| | Gas | Intermediate | 1,417 |
| |
Mystic 7 | New England | Charlestown, MA | 1 |
| | Oil/Gas | Intermediate | 573 |
| (m) |
Wyman | New England | Yarmouth, ME | 1 |
| 5.9 |
| Oil | Intermediate | 35 |
| (e) |
West Medway | New England | West Medway, MA | 3 |
| | Oil | Peaking | 123 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
Framingham | New England | Framingham, MA | 3 |
| | Oil | Peaking | 31 |
| |
Mystic Jet | New England | Charlestown, MA | 1 |
| | Oil | Peaking | 9 |
| (m) |
Total New England | | | | | | | 2,203 |
| |
| | | | | | | | |
Nine Mile Point | New York | Scriba, NY | 2 |
| 50.01 |
| Uranium | Base-load | 838 |
| (e)(f) |
FitzPatrick | New York | Scriba, NY | 1 |
| | Uranium | Base-load | 842 |
| |
Ginna | New York | Ontario, NY | 1 |
| 50.01 |
| Uranium | Base-load | 288 |
| (e)(f) |
Solar New York | New York | Bethlehem, NY | 1 |
| | Solar | Base-load | 3 |
| |
Total New York | | | | | | | 1,971 |
| |
| | | | | | | | |
Antelope Valley | Other | Lancaster, CA | 1 |
| | Solar | Base-load | 242 |
| |
Bluestem | Other | Beaver County, OK | 60 |
| 51 |
| Wind | Base-load | 101 |
| (e)(g)(h) |
Exelon Wind 4 | Other | Gruver, TX | 38 |
| | Wind | Base-load | 80 |
| |
Shooting Star | Other | Kiowa County, KS | 65 |
| 51 |
| Wind | Base-load | 53 |
| (e)(g) |
Albany Green Energy | Other | Albany, GA | 1 |
| 99 |
| Biomass | Base-load | 52 |
| (i) |
Solar Arizona | Other | Various, AZ | 127 |
| | Solar | Base-load | 46 |
| |
Bluegrass Ridge | Other | King City, MO | 27 |
| 51 |
| Wind | Base-load | 29 |
| (e)(g) |
California PV Energy 2 | Other | Various, CA | 89 |
| | Solar | Base-load | 27 |
| |
Conception | Other | Barnard, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Cow Branch | Other | Rock Port, MO | 24 |
| 51 |
| Wind | Base-load | 26 |
| (e)(g) |
Solar Arizona 2 | Other | Various, AZ | 25 |
| | Solar | Base-load | 23 |
| |
California PV Energy | Other | Various, CA | 53 |
| | Solar | Base-load | 21 |
| |
Mountain Home | Other | Glenns Ferry, ID | 20 |
| 51 |
| Wind | Base-load | 21 |
| (e)(g) |
High Mesa | Other | Elmore Co., ID | 19 |
| 51 |
| Wind | Base-load | 20 |
| (e)(g) |
Echo 1 | Other | Echo, OR | 21 |
| 50.49 |
| Wind | Base-load | 17 |
| (e)(g) |
Sacramento PV Energy | Other | Sacramento, CA | 4 |
| 51 |
| Solar | Base-load | 15 |
| (e)(g) |
Cassia | Other | Buhl, ID | 14 |
| 51 |
| Wind | Base-load | 15 |
| (e)(g) |
Wildcat | Other | Lovington, NM | 13 |
| 51 |
| Wind | Base-load | 14 |
| (e)(g) |
Echo 2 | Other | Echo, OR | 10 |
| 51 |
| Wind | Base-load | 10 |
| (e)(g) |
Exelon Wind 5 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 6 | Other | Texhoma, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 7 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 8 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 9 | Other | Sunray, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 10 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
Exelon Wind 11 | Other | Dumas, TX | 8 |
| | Wind | Base-load | 10 |
| |
|
| | | | | | | | | | | |
Station(a) | Region | Location | No. of Units | Percent Owned(b) | Primary Fuel Type | Primary Dispatch Type(c) | Net Generation Capacity (MW)(d) | |
High Plains | Other | Panhandle, TX | 8 |
| 99.5 |
| Wind | Base-load | 10 |
| (e) |
Solar Georgia 2 | Other | Various, GA | 8 |
| | Solar | Base-load | 10 |
| |
Tuana Springs | Other | Hagerman, ID | 8 |
| 51 |
| Wind | Base-load | 9 |
| (e)(g) |
Solar Georgia | Other | Various, GA | 10 |
| | Solar | Base-load | 8 |
| |
Greensburg | Other | Greensburg, KS | 10 |
| 51 |
| Wind | Base-load | 7 |
| (e)(g) |
Outback Solar | Other | Christmas Valley, OR | 1 |
| | Solar | Base-load | 6 |
| |
Echo 3 | Other | Echo, OR | 6 |
| 50.49 |
| Wind | Base-load | 5 |
| (e)(g) |
Three Mile Canyon | Other | Boardman, OR | 6 |
| 51 |
| Wind | Base-load | 5 |
| (e)(g) |
Loess Hills | Other | Rock Port, MO | 4 |
| | Wind | Base-load | 5 |
| |
California PV Energy 3 | Other | Various, CA | 10 |
| | Solar | Base-load | 5 |
| |
Mohave Sunrise Solar | Other | Fort Mohave, AZ | 1 |
| | Solar | Base-load | 5 |
| |
Denver Airport Solar | Other | Denver, CO | 1 |
| 51 |
| Solar | Base-load | 2 |
| (e)(g) |
Hillabee | Other | Alexander City, AL | 3 |
| | Gas | Intermediate | 753 |
| |
Grande Prairie | Other | Alberta, Canada | 1 |
| | Gas | Peaking | 105 |
| |
SEGS 4, 5, 6 | Other | Boron, CA | 3 |
| 4.2-12.2 |
| Solar | Peaking | 9 |
| (e) |
Total Other | | | | | | | 1,852 |
| |
Total | | | | | | | 32,463 |
| |
__________
| |
(a) | All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors. |
| |
(b) | 100%, unless otherwise indicated. |
| |
(c) | Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. |
| |
(d) | For nuclear stations, capacity reflects the annual mean rating. Fossil stations reflect a summer rating. Wind and solar facilities reflect name plate capacity. |
| |
(e) | Net generation capacity is stated at proportionate ownership share. |
| |
(f) | Reflects Generation’s 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of 82% of Nine Mile Point Unit 2. |
| |
(g) | Reflects the sale of 49% of EGRP to a third party on July 6, 2017. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(h) | EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets. |
| |
(i) | Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity. |
| |
(j) | Generation has announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(k) | Generation has agreed to retire and cease generation operations at the Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit 8), Westport and Pennsbury units on or before June 1, 2020. |
| |
(l) | Generation plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019. |
| |
(m) | Generation plans to retire and cease generation operation at the Mystic 7 and Mystic Jet units on or about June 1, 2022. |
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance, refueling, repairs or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
ComEd
ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ComEd’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
765,000 | | 90 |
345,000 | | 2,716 |
138,000 | | 2,209 |
ComEd’s electric distribution system includes 35,398 circuit miles of overhead lines and 32,010 circuit miles of underground lines.
First Mortgage and Insurance
The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First Mortgage Bonds are issued.
ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ComEd.
PECO
PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | | |
Voltage (Volts) | | Circuit Miles | |
500,000 | | 188 | (a) |
230,000 | | 549 | |
138,000 | | 135 | |
69,000 | | 181 | |
__________
| |
(a) | In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines located in Delaware and New Jersey. |
PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,367 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 9 |
|
Distribution | 6,912 |
|
Service piping | 6,377 |
|
Total | 13,298 |
|
PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 160 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 30 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.
First Mortgage and Insurance
The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and refunding mortgage bonds are issued.
PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of PECO.
BGE
BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 218 |
230,000 | | 358 |
138,000 | | 55 |
115,000 | | 706 |
BGE’s electric distribution system includes 9,191 circuit miles of overhead lines and 17,295 circuit miles of underground lines.
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission | 161 |
|
Distribution | 7,348 |
|
Service piping | 6,305 |
|
Total | 13,814 |
|
BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,056 mmcf and a send-out capacity of 332 mmcf/day and a propane-air plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.
Property Insurance
BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, BGE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of BGE.
Pepco
Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 142 |
230,000 | | 767 |
138,000 | | 61 |
115,000 | | 38 |
Pepco’s electric distribution system includes approximately 4,127 circuit miles of overhead lines and 7,039 circuit miles of underground lines. Pepco also operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed through a sale and leaseback transaction.
First Mortgage and Insurance
The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First Mortgage Bonds are issued.
Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of Pepco.
DPL
DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
DPL’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows: |
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | 16 |
230,000 | | 471 |
138,000 | | 586 |
69,000 | | 569 |
DPL’s electric distribution system includes approximately 6,031 circuit miles of overhead lines and 6,298 circuit miles of underground lines. DPL also owns and operates a distribution system control center in New Castle, Delaware.
Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2018:
|
| | |
| Pipeline Miles |
Transmission (a) | 8 |
|
Distribution | 2,065 |
|
Service piping | 1,398 |
|
Total | 3,471 |
|
___________
| |
(a) | DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and by 90% owner for distribution of natural gas to its electric generating facilities. |
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 250 mmcf and an emergency sendout capability of 36 mmcf/day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary delivery point contractual entitlement of 158 mmcf/day.
First Mortgage and Insurance
The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First Mortgage Bonds are issued.
DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of DPL.
ACE
ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ACE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
|
| | |
Voltage (Volts) | | Circuit Miles |
500,000 | | — |
230,000 | | 221 |
138,000 | | 239 |
69,000 | | 663 |
ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,927 circuit miles of underground lines. ACE also owns and operates a distribution system control center in Mays Landing, New Jersey.
First Mortgage and Insurance
The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First Mortgage Bonds are issued.
ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of ACE.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at certain critical locations, enhanced response and recovery plans, long-term design changes and redundancy measures. Additionally, the energy industry has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed in order to maintain the reliability of the country’s energy systems.
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
|
| |
ITEM 4. | MINE SAFETY DISCLOSURES |
All Registrants
Not Applicable to the Registrants.
PART II
(Dollars in millions except per share data, unless otherwise noted)
|
| |
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
Exelon
Exelon’s common stock is listed on the New York Stock Exchange (trading symbol: EXC). As of January 31, 2019, there were 969,745,933 shares of common stock outstanding and approximately 99,857 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock, as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2014 through 2018.
This performance chart assumes:
$100 invested on December 31, 2013 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and
All dividends are reinvested.
|
| | | | | | |
Value of Investment at December 31, |
| 2013 | 2014 | 2015 | 2016 | 2017 | 2018 |
Exelon Corporation | $100 | $140.61 | $109.44 | $145.34 | $167.22 | $197.86 |
S&P 500 | $100 | $113.68 | $115.24 | $129.02 | $157.17 | $150.27 |
S&P Utilities | $100 | $128.98 | $122.73 | $142.72 | $160.00 | $166.57 |
Generation
As of January 31, 2019, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2019, there were 127,021,331 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were indirectly held by Exelon. At January 31, 2019, in addition to Exelon, there were 294 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2019, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
BGE
As of January 31, 2019, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2019, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2019, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2019, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2019, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s
senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
At December 31, 2018, Exelon had retained earnings of $14,766 million, including Generation’s undistributed earnings of $3,724 million, ComEd’s retained earnings of $1,337 million consisting of retained earnings appropriated for future dividends of $2,976 million, partially offset by $1,639 million of unappropriated accumulated deficits, PECO’s retained earnings of $1,242 million, BGE’s retained earnings of $1,640 million, and PHI's undistributed earnings of $62 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2018 and 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 |
(per share) | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
Exelon | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.345 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
|
The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's quarterly common dividend payments:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 |
(in millions) | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter | | 4th Quarter | | 3rd Quarter | | 2nd Quarter | | 1st Quarter |
Generation | $ | 313 |
| | $ | 311 |
| | $ | 189 |
| | $ | 188 |
| | $ | 165 |
| | $ | 164 |
| | $ | 166 |
| | $ | 164 |
|
ComEd | 114 |
| | 116 |
| | 115 |
| | 114 |
| | 106 |
| | 105 |
| | 106 |
| | 105 |
|
PECO | 6 |
| | 7 |
| | 6 |
| | 287 |
| | 72 |
| | 72 |
| | 72 |
| | 72 |
|
BGE | 52 |
| | 52 |
| | 53 |
| | 52 |
| | 50 |
| | 49 |
| | 50 |
| | 49 |
|
PHI | 94 |
| | 123 |
| | 38 |
| | 71 |
| | 44 |
| | 136 |
| | 62 |
| | 69 |
|
Pepco | 41 |
| | 78 |
| | 25 |
| | 25 |
| | — |
| | 75 |
| | 28 |
| | 30 |
|
DPL | 38 |
| | 18 |
| | 4 |
| | 36 |
| | 30 |
| | 28 |
| | 24 |
| | 30 |
|
ACE | 13 |
| | 27 |
| | 10 |
| | 9 |
| | 15 |
| | 31 |
| | 12 |
| | 10 |
|
First Quarter 2019 Dividend
On February 5, 2019, the Exelon Board of Directors declared a first quarter 2019 regular quarterly dividend of $0.3625 per share on Exelon’s common stock payable on March 8, 2019, to shareholders of record of Exelon at the end of the day on February 20, 2019.
|
| |
ITEM 6. | SELECTED FINANCIAL DATA |
Exelon
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions, except per share data) | 2018 | | 2017(c, d) | | 2016(a, c, d) | | 2015(c) | | 2014(b,c) |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 35,985 |
| | $ | 33,565 |
| | $ | 31,366 |
| | $ | 29,447 |
| | $ | 27,429 |
|
Operating income | 3,898 |
| | 4,395 |
| | 3,212 |
| | 4,554 |
| | 3,210 |
|
Net income | 2,084 |
|
| 3,876 |
|
| 1,196 |
|
| 2,250 |
|
| 1,820 |
|
Net income attributable to common shareholders | 2,010 |
| | 3,786 |
| | 1,121 |
| | 2,269 |
| | 1,623 |
|
Earnings per average common share (diluted): | | | | | | | | | |
Net income | $ | 2.07 |
| | $ | 3.99 |
| | $ | 1.21 |
| | $ | 2.54 |
| | $ | 1.88 |
|
Dividends per common share | $ | 1.38 |
| | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| | $ | 1.24 |
|
__________
| |
(a) | The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016. |
| |
(b) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(c) | Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(d) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015(a) | | 2014(a) |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 13,360 |
| | $ | 11,896 |
| | $ | 12,451 |
| | $ | 15,334 |
| | $ | 11,853 |
|
Property, plant and equipment, net | 76,707 |
| | 74,202 |
| | 71,555 |
| | 57,439 |
| | 52,170 |
|
Total assets | 119,666 |
|
| 116,770 |
|
| 114,952 |
|
| 95,384 |
|
| 86,416 |
|
Current liabilities | 11,404 |
| | 10,798 |
| | 13,463 |
| | 9,118 |
| | 8,762 |
|
Long-term debt, including long-term debt to financing trusts | 34,465 |
| | 32,565 |
| | 32,216 |
| | 24,286 |
| | 19,853 |
|
Shareholders’ equity | 30,764 |
| | 29,896 |
| | 25,860 |
| | 25,793 |
| | 22,608 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017(b) | | 2016(b) | | 2015 | | 2014(a) |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 20,437 |
| | $ | 18,500 |
| | $ | 17,757 |
| | $ | 19,135 |
| | $ | 17,393 |
|
Operating income | 975 |
| | 947 |
| | 820 |
| | 2,275 |
| | 1,176 |
|
Net income | 443 |
| | 2,798 |
| | 550 |
| | 1,340 |
| | 1,019 |
|
__________
| |
(a) | On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully consolidated basis. |
| |
(b) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017(a) | | 2016(a) | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 8,433 |
| | $ | 6,882 |
| | $ | 6,567 |
| | $ | 6,342 |
| | $ | 7,311 |
|
Property, plant and equipment, net | 23,981 |
| | 24,906 |
| | 25,585 |
| | 25,843 |
| | 23,028 |
|
Total assets | 47,556 |
|
| 48,457 |
|
| 47,022 |
|
| 46,529 |
|
| 44,951 |
|
Current liabilities | 5,769 |
| | 4,191 |
| | 5,689 |
| | 4,933 |
| | 4,459 |
|
Long-term debt, including long-term debt to affiliates | 7,887 |
| | 8,644 |
| | 8,124 |
| | 8,869 |
| | 7,582 |
|
Member’s equity | 13,204 |
| | 13,669 |
| | 11,505 |
| | 11,635 |
| | 12,718 |
|
| |
(a) | Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this guidance and are not comparative. |
ComEd
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 5,882 |
| | $ | 5,536 |
| | $ | 5,254 |
| | $ | 4,905 |
| | $ | 4,564 |
|
Operating income | 1,146 |
| | 1,323 |
| | 1,205 |
| | 1,017 |
| | 980 |
|
Net income | 664 |
| | 567 |
| | 378 |
| | 426 |
| | 408 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 1,570 |
| | $ | 1,364 |
| | $ | 1,554 |
| | $ | 1,518 |
| | $ | 1,723 |
|
Property, plant and equipment, net | 22,058 |
| | 20,723 |
| | 19,335 |
| | 17,502 |
| | 15,793 |
|
Total assets | 31,213 |
|
| 29,726 |
|
| 28,335 |
|
| 26,532 |
|
| 25,358 |
|
Current liabilities | 1,925 |
| | 2,294 |
| | 2,938 |
| | 2,766 |
| | 1,923 |
|
Long-term debt, including long-term debt to financing trusts | 8,006 |
| | 6,966 |
| | 6,813 |
| | 6,049 |
| | 5,870 |
|
Shareholders’ equity | 10,247 |
| | 9,542 |
| | 8,725 |
| | 8,243 |
| | 7,907 |
|
PECO
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 3,038 |
| | $ | 2,870 |
| | $ | 2,994 |
| | $ | 3,032 |
| | $ | 3,094 |
|
Operating income | 587 |
| | 655 |
| | 702 |
| | 630 |
| | 572 |
|
Net income | 460 |
| | 434 |
| | 438 |
| | 378 |
| | 352 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 782 |
| | $ | 822 |
| | $ | 757 |
| | $ | 842 |
| | $ | 645 |
|
Property, plant and equipment, net | 8,610 |
| | 8,053 |
| | 7,565 |
| | 7,141 |
| | 6,801 |
|
Total assets | 10,642 |
|
| 10,170 |
|
| 10,831 |
|
| 10,367 |
|
| 9,860 |
|
Current liabilities | 809 |
| | 1,267 |
| | 727 |
| | 944 |
| | 653 |
|
Long-term debt, including long-term debt to financing trusts | 3,268 |
| | 2,587 |
| | 2,764 |
| | 2,464 |
| | 2,416 |
|
Shareholder's equity | 3,820 |
| | 3,577 |
| | 3,415 |
| | 3,236 |
| | 3,121 |
|
BGE
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data: | | | | | | | | | |
Operating revenues | $ | 3,169 |
| | $ | 3,176 |
| | $ | 3,233 |
| | $ | 3,135 |
| | $ | 3,165 |
|
Operating income | 474 |
| | 614 |
| | 550 |
| | 558 |
| | 439 |
|
Net income | 313 |
| | 307 |
| | 294 |
| | 288 |
| | 211 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Balance Sheet data: | | | | | | | | | |
Current assets | $ | 786 |
| | $ | 811 |
| | $ | 842 |
| | $ | 845 |
| | $ | 951 |
|
Property, plant and equipment, net | 8,243 |
| | 7,602 |
| | 7,040 |
| | 6,597 |
| | 6,204 |
|
Total assets | 9,716 |
|
| 9,104 |
|
| 8,704 |
|
| 8,295 |
|
| 8,056 |
|
Current liabilities | 774 |
| | 760 |
| | 707 |
| | 1,134 |
| | 794 |
|
Long-term debt, including long-term debt to financing trusts | 2,876 |
| | 2,577 |
| | 2,533 |
| | 1,732 |
| | 2,109 |
|
Shareholder's equity | 3,354 |
| | 3,141 |
| | 2,848 |
| | 2,687 |
| | 2,563 |
|
PHI
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | March 24 to December 31 | | | January 1 to March 23, | | For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | | | |
Operating revenues | $ | 4,805 |
| | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $4,935 | | $ | 4,808 |
|
Operating income | 650 |
| | 769 |
| | 93 |
| | | 105 |
| | 673 |
| | 605 |
|
Net income (loss) from continuing operations | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| | 242 |
|
Net income (loss) | 398 |
| | 362 |
| | (61 | ) | | | 19 |
| | 327 |
| | 242 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| December 31, | | | December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | | 2015 |
Balance Sheet data(a): | | | | | | | | |
Current assets | $ | 1,533 |
| | $ | 1,551 |
| | $ | 1,838 |
| | | $ | 1,474 |
|
Property, plant and equipment, net | 13,446 |
| | 12,498 |
| | 11,598 |
| | | 10,864 |
|
Total assets | 21,984 |
| | 21,247 |
| | 21,025 |
| | | 16,188 |
|
Current liabilities | 1,592 |
| | 1,931 |
| | 2,284 |
| | | 2,327 |
|
Long-term debt | 6,134 |
| | 5,478 |
| | 5,645 |
| | | 4,823 |
|
Preferred Stock | — |
| | — |
| | — |
| | | 183 |
|
Member’s equity/Shareholders' equity | 9,282 |
| | 8,825 |
| | 8,016 |
| | | 4,413 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above. |
Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety by reference to and should be read in conjunction with Pepco’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 2,239 |
| | $ | 2,158 |
| | $ | 2,186 |
| | $ | 2,129 |
| | $ | 2,055 |
|
Operating income | 320 |
| | 399 |
| | 174 |
| | 385 |
| | 349 |
|
Net income | 210 |
| | 205 |
| | 42 |
| | 187 |
| | 171 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 760 |
| | $ | 710 |
| | $ | 684 |
| | $ | 726 |
|
Property, plant and equipment, net | 6,460 |
| | 6,001 |
| | 5,571 |
| | 5,162 |
|
Total assets | 8,299 |
| | 7,832 |
| | 7,335 |
| | 6,908 |
|
Current liabilities | 628 |
| | 550 |
| | 596 |
| | 455 |
|
Long-term debt | 2,704 |
| | 2,521 |
| | 2,333 |
| | 2,340 |
|
Shareholder's equity | 2,740 |
| | 2,533 |
| | 2,300 |
| | 2,240 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above. |
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by reference to and should be read in conjunction with DPL’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 1,332 |
| | $ | 1,300 |
| | $ | 1,277 |
| | $ | 1,302 |
| | $ | 1,282 |
|
Operating income | 190 |
| | 229 |
| | 50 |
| | 165 |
| | 207 |
|
Net income (loss) | 120 |
| | 121 |
| | (9 | ) | | 76 |
| | 104 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 336 |
| | $ | 325 |
| | $ | 370 |
| | $ | 388 |
|
Property, plant and equipment, net | 3,821 |
| | 3,579 |
| | 3,273 |
| | 3,070 |
|
Total assets | 4,588 |
| | 4,357 |
| | 4,153 |
| | 3,969 |
|
Current liabilities | 375 |
| | 547 |
| | 381 |
| | 564 |
|
Long-term debt | 1,403 |
| | 1,217 |
| | 1,221 |
| | 1,061 |
|
Shareholder's equity | 1,509 |
| | 1,335 |
| | 1,326 |
| | 1,237 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above. |
ACE
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by reference to and should be read in conjunction with ACE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
Statement of Operations data(a): | | | | | | | | | |
Operating revenues | $ | 1,236 |
| | $ | 1,186 |
| | $ | 1,257 |
| | $ | 1,295 |
| | $ | 1,210 |
|
Operating income | 149 |
| | 157 |
| | 7 |
| | 134 |
| | 137 |
|
Net income (loss) | 75 |
| | 77 |
| | (42 | ) | | 40 |
| | 46 |
|
|
| | | | | | | | | | | | | | | |
| December 31, |
(In millions) | 2018 | | 2017 | | 2016 | | 2015 |
Balance Sheet data(a): | | | | | | | |
Current assets | $ | 240 |
| | $ | 258 |
| | $ | 399 |
| | $ | 546 |
|
Property, plant and equipment, net | 2,966 |
| | 2,706 |
| | 2,521 |
| | 2,322 |
|
Total assets | 3,699 |
| | 3,445 |
| | 3,457 |
| | $ | 3,387 |
|
Current liabilities | 422 |
| | 619 |
| | 320 |
| | $ | 297 |
|
Long-term debt | 1,170 |
| | 840 |
| | 1,120 |
| | 1,153 |
|
Shareholder's equity | 1,126 |
| | 1,043 |
| | 1,034 |
| | 1,000 |
|
__________
| |
(a) | As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above. |
|
| |
Item 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has twelve reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions), ComEd, PECO, BGE, Pepco, DPL and ACE. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 - Significant Accounting Policies and Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis of Financial Condition and Results of Operations 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.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for the year ended December 31, 2018 compared to the same period in 2017 and December 31, 2017 compared to the same period in 2016. For additional information regarding the financial results for the years ended December 31, 2018, 2017 and 2016 see the discussions of Results of Operations by Registrant.
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Exelon | $ | 2,010 |
| | $ | 3,786 |
| | $ | (1,776 | ) | | $ | 1,121 |
| | $ | 2,665 |
|
Generation | 370 |
| | 2,710 |
| | (2,340 | ) | | 483 |
| | 2,227 |
|
ComEd | 664 |
| | 567 |
| | 97 |
| | 378 |
| | 189 |
|
PECO | 460 |
| | 434 |
| | 26 |
| | 438 |
| | (4 | ) |
BGE | 313 |
| | 307 |
| | 6 |
| | 286 |
| | 21 |
|
Pepco | 210 |
| | 205 |
| | 5 |
| | 42 |
| | 163 |
|
DPL | 120 |
| | 121 |
| | (1 | ) | | (9 | ) | | 130 |
|
ACE | 75 |
| | 77 |
| | (2 | ) | | (42 | ) | | 119 |
|
Other(b) | (195 | ) | | (594 | ) | | 399 |
| | (422 | ) | | (172 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to March 23, |
| 2018 | | 2017 | | | 2016 | | | 2016 |
PHI(a) | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
__________
| |
(a) | Includes the consolidated results of Pepco, DPL and ACE. |
| |
(b) | Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities. |
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017. Net income attributable to common shareholders decreased by $1,776 million and diluted earnings per average common share decreased to $2.07 in 2018 from $3.99 in 2017 primarily due to:
Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;
The gain associated with the FitzPatrick acquisition in 2017;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017;
Long-lived asset impairments of certain merchant wind assets in West Texas; and
Increased storm costs at PECO and BGE.
The decreases were partially offset by;
The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net realized gains on NDT funds;
The gain on the settlement of a long-term gas supply agreement;
Decreased nuclear outage days;
Increased electric distribution and energy efficiency formula rate earnings at ComEd;
Regulatory rate increases at PECO, BGE and PHI;
The impact of favorable weather at PECO, DPL and ACE; and
The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The decrease in diluted earnings per share was also due to the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Net income attributable to common shareholdersincreased by $2,665 million and diluted earnings per average common share increased to $3.99 in 2017 from $1.21 in 2016 primarily due to:
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities;
Higher net unrealized and realized gains on NDT funds;
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices;
Decreased nuclear outage days;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012 Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment in 2016;
Increased electric distribution and transmission formula rate earnings at ComEd;
Regulatory rate increases at BGE and PHI; and
Penalties and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange position in 2016.
The increases were partially offset by;
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility;
Increased mark-to-market losses;
The impact of unfavorable weather at ComEd, PECO, DPL and ACE; and
The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The net increase in diluted earnings per share from the items listed above was partially offset by the impact of the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common stock issuance.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP) operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and Adjusted (non-GAAP) operating earnings for the year ended December 31, 2018 as compared to 2017 and 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
(All amounts after tax; in millions, except per share amounts) | | | Earnings per Diluted Share | | | | Earnings per Diluted Share | | | | Earnings per Diluted Share |
Net Income Attributable to Common Shareholders | $ | 2,010 |
| | $ | 2.07 |
| | $ | 3,786 |
| | $ | 3.99 |
| | $ | 1,121 |
| | $ | 1.21 |
|
Mark-to-Market Impact of Economic Hedging Activities(a) (net of taxes of $89, $68 and $18, respectively) | 252 |
| | 0.26 |
| | 107 |
| | 0.11 |
| | 24 |
| | 0.03 |
|
Unrealized Losses (Gains) Related to NDT Funds(b) (net of taxes of $289, $286 and $112, respectively) | 337 |
| | 0.35 |
| | (318 | ) | | (0.34 | ) | | (118 | ) | | (0.13 | ) |
Amortization of Commodity Contract Intangibles(c) (net of taxes of $0, $22 and $22, respectively) | — |
| | — |
| | 34 |
| | 0.04 |
| | 35 |
| | 0.04 |
|
Merger and Integration Costs(d) (net of taxes of $2, $25 and $50, respectively) | 3 |
| | — |
| | 40 |
| | 0.04 |
| | 114 |
| | 0.12 |
|
Merger Commitments(e) (net of taxes of $0, $137 and $126, respectively) | — |
| | — |
| | (137 | ) | | (0.14 | ) | | 437 |
| | 0.47 |
|
Long-Lived Asset Impairments(f) (net of taxes of $13, $204 and $68, respectively) | 35 |
| | 0.04 |
| | 321 |
| | 0.34 |
| | 103 |
| | 0.11 |
|
Plant Retirements and Divestitures(g) (net of taxes of $181, $134 and $273, respectively) | 512 |
| | 0.53 |
| | 207 |
| | 0.22 |
| | 432 |
| | 0.47 |
|
Cost Management Program(h) (net of taxes of $16, $21 and $21, respectively) | 48 |
| | 0.05 |
| | 34 |
| | 0.04 |
| | 34 |
| | 0.04 |
|
Annual Asset Retirement Obligation Update(i) (net of taxes of $7, $1 and $13, respectively) | 20 |
| | 0.02 |
| | (2 | ) | | — |
| | (75 | ) | | (0.08 | ) |
Vacation Policy Change(j) (net of taxes of $0, $21 and $0, respectively) | — |
| | — |
| | (33 | ) | | (0.03 | ) | | — |
| | — |
|
Change in Environmental Liabilities (net of taxes of $0, $17 and $0, respectively) | (1 | ) | | — |
| | 27 |
| | 0.03 |
| | — |
| | — |
|
Bargain Purchase Gain(k) (net of taxes of $0, $0 and $0, respectively) | — |
| | — |
| | (233 | ) | | (0.25 | ) | | — |
| | — |
|
Gain on Deconsolidation of Business(l) (net of taxes of $0, $83 and $0, respectively) | — |
| | — |
| | (130 | ) | | (0.14 | ) | | — |
| | — |
|
Gain on Contract Settlement(m) (net of taxes of $20, $0 and $0, respectively) | (55 | ) | | (0.06 | ) | | — |
| | — |
| | — |
| | — |
|
Like-Kind Exchange Tax Position(n) (net of taxes of $0, $66 and $61, respectively) | — |
| | — |
| | (26 | ) | | (0.03 | ) | | 199 |
| | 0.21 |
|
Curtailment of Generation Growth and Development Activities(o) (net of taxes of $0, $0 and $35, respectively) | — |
| | — |
| | — |
| | — |
| | 57 |
| | 0.06 |
|
Reassessment of Deferred Income Taxes(p) (entire amount represents tax expense) | (22 | ) | | (0.02 | ) | | (1,299 | ) | | (1.37 | ) | | 10 |
| | 0.01 |
|
Tax Settlements(q) (net of taxes of $0, $1 and $0, respectively) | — |
| | — |
| | (5 | ) | | (0.01 | ) | | — |
| | — |
|
Noncontrolling Interests(r) (net of taxes of $24, $24 and $9, respectively) | (113 | ) | | (0.12 | ) | | 114 |
| | 0.12 |
| | 102 |
| | 0.11 |
|
Adjusted (non-GAAP) Operating Earnings | $ | 3,026 |
| | $ | 3.12 |
| | $ | 2,487 |
| | $ | 2.62 |
| | $ | 2,475 |
| | $ | 2.67 |
|
__________
Note:
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2018, 2017 and 2016 ranged from 26.0 percent to 29.0 percent, 39.0 percent to 41.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized gains and losses related to NDT funds were 46.2 percent, 47.4 percent and 48.7 percent for the years ended December 31, 2018, 2017 and 2016, respectively.
| |
(a) | Reflects the impact of net losses on economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information related to hedging activities. |
| |
(b) | Reflects the impact of net unrealized gains and losses on Generation’s NDT funds for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact. |
| |
(c) | Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions. |
| |
(d) | Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e) | Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017, primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions. |
| |
(f) | In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation. |
| |
(g) | In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its electrical contracting business. |
| |
(h) | Primarily represents severance and reorganization costs related to a cost management program. |
| |
(i) | For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property. |
| |
(j) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(k) | Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition. |
| |
(l) | Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. |
| |
(m) | Represents the gain on the settlement of a long-term gas supply agreement at Generation. |
| |
(n) | Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in 2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax position. |
| |
(o) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(p) | Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In 2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment. |
| |
(q) | Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests. |
| |
(r) | Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and losses on NDT funds at CENG. |
Significant 2018 Transactions and Recent Developments
Regulatory Implications of the Tax Cuts and Jobs Act (TCJA)
The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 million in ongoing annual savings to be returned to customers related to TCJA from their distribution utility operations. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Utility Distribution Base Rate Case Proceedings
|
| | | | | | | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
PECO - Pennsylvania (Electric) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
Pepco - District of Columbia (Electric) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
DPL - Maryland (Electric) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Pending Distribution Base Rate Case Proceedings
|
| | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase | | Requested ROE | Expected Approval Timing |
ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019 |
Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed above. |
Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
|
| | | | | | | | | | | | | | |
Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase) | | Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) | | 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
Pepco | 6 |
| 2 |
| 8 |
| | 7.82 | % | 10.50 | % |
DPL | 14 |
| 13 |
| 27 |
| | 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
| | 8.02 | % | 10.50 | % |
__________
| |
(a) | The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted. |
| |
(b) | The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and equity return on transmission rate bases. |
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included
an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Illinois ZEC Procurement
Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. During the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle and permanently ceased generation operations in September 2018. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September 30, 2019. The plant is currently committed to operate through May 2019. As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI, Exelon and Generation will also recognize annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2019 due to the early retirement decisions.
|
| | | | | | | | |
| | Actual | | Projected(a) |
Income statement expense (pre-tax) | | 2018 | | 2019 |
Depreciation and Amortization(b) | | | | |
Accelerated depreciation(c) | | $ | 539 |
| | $ | 230 |
|
Accelerated nuclear fuel amortization | | 57 |
| | 5 |
|
Operating and maintenance(d) | | 32 |
| | 5 |
|
Total | | $ | 628 |
| | $ | 240 |
|
_________
| |
(a) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
| |
(b) | Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(c) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(d) | Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments. |
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for,
and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 4 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
The ISO-NE announced that it would take a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. On January 4, 2019, Generation notified ISO–NE that it will participate in the Forward Capacity Market auction for the 2022 – 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022–2023 capacity commitment period. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension Plan Merger
Effective January 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial
losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $90 million.
Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the Registrants for the twelve months ended December 31, 2018 are presented below:
|
| | | | | | | | | | |
| | | (in millions) |
| Customer Outages | | Incremental Operating & Maintenance | | Incremental Capital Expenditures |
Exelon | 1,727,000 |
| | $ | 88 |
| (b) | $ | 85 |
|
PECO | 750,000 |
| | 53 |
| | 34 |
|
BGE | 425,000 |
| | 31 |
| | 16 |
|
PHI(a) | 552,000 |
| | 4 |
| (b) | 35 |
|
Pepco | 182,000 |
| | 2 |
| (b) | 4 |
|
DPL | 138,000 |
| | 2 |
| (b) | 4 |
|
ACE | 232,000 |
| | — |
| (b) | 27 |
|
________
| |
(a) | PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE. |
| |
(b) | Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21 million, respectively. |
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were assumed by Brookfield on the closing date.
Exelon’s Strategy and Outlook for 2019 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths 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:
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean and affordable energy. Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and 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-facing activities foster development and delivery of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy markets.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth. Exelon’s Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for additional information regarding market and financial factors.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018. Approximately 75% of the savings were related to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs, through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount related to the Utility Registrants. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas and offering sustainable returns.
Regulated Energy Businesses. The PHI merger enhances Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $29 billion over the next five years in electric and natural gas infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately $16 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to customers and the community by
increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid Investments and infrastructure development and enhancement programs.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to ensure appropriate valuation of its generation assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching as a means to provide stable earnings, and identify emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Liquidity Considerations
Each of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6 billion, $5.3 billion, $1.0 billion, $0.6 billion, $0.6 billion, $0.3 billion, $0.3 billion and $0.3 billion, respectively. Generation also has bilateral credit facilities with aggregate maximum availability of $0.5 billion. See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
For additional information regarding the Registrants' liquidity for the year ended December 31, 2018, see Liquidity and Capital Resources discussion below.
Project Financing
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities of $0.2 billion as of December 31, 2018. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility Registrants’ current and future results
of operations, cash flows and financial positions. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have declined significantly over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is selected as an eligible facility under the New Jersey ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second
alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement (FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates, environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC) and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict the final outcome of each of these proceedings or their potential financial impact, if any, on Exelon or Generation.
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of Commerce (DOC) seeking relief under Section 232 of the Trade Expansion Act of 1962 (as amended) from imports of uranium products, alleging that these imports threaten national security (the Petition). The Trade Expansion Act of 1962 (the Act) was promulgated by Congress to protect essential national security industries whose survival is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors to purchase at least 25% of their uranium needs from domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a material, unfavorable impact on Exelon’s and Generation’s financial statements.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain generation facilities. Exelon has been and will continue to be an active
participant in these proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd, BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.2)%, (0.1)%, 0.3%, (0.3)% and (1.5)%, respectively, in 2019 compared to 2018. PECO is projecting load volumes to be flat in 2019 compared to 2018.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
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, second, third and fourth quarter 2018 dividends of $0.3450 per share each on Exelon's common stock, and the first quarter 2019 dividends declared was $0.3625. The dividends for the first, second, third and fourth quarter 2018 were paid on March 9, 2018, June 8, 2018, September 10, 2018 and December 10, 2018, respectively. The first quarter 2019 dividend is payable on March 8, 2019.
Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend.
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 2019 and 2020. 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 December 31, 2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35% for 2019, 2020, and 2021 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 potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 62% of Generation’s uranium concentrate requirements from 2019 through 2023 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 positions.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama 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 coal-fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older, marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil fuel plants.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard (NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard 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. 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. On April 27, 2017, the D.C. Circuit granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s EO discussed above. Following EPA’s review and determination of its course of action for the MATS rule, the parties will have 30 days to file motions on future proceedings. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the "appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal challenge.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP) to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the EPA. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG emissions. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to compel EPA to issue the designations.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1. BUSINESS, "Global Climate Change" for additional information.
Water Quality
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts and is implemented through state-level NPDES permit programs. All 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 recent changes to the regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" for further discussion.additional information.
Solid and Hazardous 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 as non-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 accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements 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 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detailadditional information related to environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
Delaware Distribution System Investment Charge
On June 14, 2018, the Governor of Delaware signed new Distribution System Investment Charge (DSIC) legislation, which establishes a system improvement charge that provides a mechanism to recover infrastructure investments, allowing for gradual rate increases and limiting frequency of distribution base rate cases. On November 30, 2018, DPL filed its first electric and gas filing in Delaware with the new rates being put into effect on January 1, 2019. This legislation supports needed infrastructure investment and allows for more timely recovery of those investments, however Exelon, PHI and DPL do not expect a material impact on the financial statements.
Pennsylvania Alternative Ratemaking
On June 28, 2018, the Governor of Pennsylvania signed Act 58 of 2018, which authorizes the PAPUC to review and approve utility-proposed alternative rate mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates. Exelon and PECO cannot predict the outcome or the potential financial impact, if any, on Exelon or PECO.
District of Columbia Clean Energy Bill
On December 18, 2018, the Council of the District of Columbia passed the Clean Energy District of Columbia Omnibus Amendment Act of 2018 (the Act), which was subsequently signed by the Mayor of the District of Columbia on January 18, 2019. The Act is expected to take effect in February 2019 following the expiration of a 30-day review process by the U.S. House of Representatives. Among other things, the Act would increase electric load by requiring all public buses, taxis and other specified fleets to be solely zero-emissions vehicles by 2045. The Act would also clarify that, under certain circumstances, the gas and electric utilities may offer and receive cost recovery including a return on investment on capital and related costs for energy efficiency programs in the District of Columbia.
Employees
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,3941,284 employees. BGE and IBEW Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. Negotiations have been productive and continue. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. In AprilNegotiations that began in 2017 Exelon Nuclearfor a first collective bargaining agreement with a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion Solutions facility are complete and the new CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully ratifiedfinalized the CBA with the IBEW union at TMI, which will expire in 2022. During 2018, Generation finalized its CBA with the SPFPASecurity Officer’s union at Braidwood, which will expire in 2021. Additionally, ACE successfully finalized two contract renewals with the IBEW Local 238210, and the new BAs will expire in 2023. As previously reported, there was an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to Local 210, collective bargaining over this small segment of employees will not commence until the issue of whether the System Operators are NLRA statutory supervisors is determined, and that matter is currently before the NLRB. Furthermore, there was an organizing effort at Quad CitiesPECO over approximately 150 Working Foreperson positions. In October 2018, the Working Foreperson group overwhelmingly rejected unionization in an election held by the NLRB. Lastly, on December 27, 2018 a representation petition was filed by the LEOSU Union seeking to an extension of three years. In June 2017,represent security officers at Clinton Power station who are currently represented by SEIU Local 1. The current collective bargaining agreement between Exelon Nuclear Security successfully ratified its CBA withand the UGSOASEIU Local 12 at Limerick to an extension of three years.1 has been extended, so that the matter between the two rival labor organizations can be resolved. No election or determination has been held and it is anticipated that this matter will be resolved in 2019.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions with its Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit Committee of the Exelon Board of Directors. Management believes that the accounting policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods. Additional discussioninformation of the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation’s ARO associated with decommissioning its nuclear units was $9.7$10.0 billion at December 31, 2017.2018. The authoritative guidance requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The availability of decommissioning trustNDT funds could impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:
Decommissioning Cost Studies
Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclear plant).updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors
Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are adjusted each year for the updated cost escalation factors.
Probabilistic Cash Flow Models
Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. Probabilities are also assignedThe assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to four differentonset of decommissioning approaches.
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1. | DECON - a method of decommissioning shortly after the cessation of operation in which the equipment, structures, and portions of a facility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level that permits property to be released for unrestricted use. Spentactivities, and (3) SAFSTOR which assumes the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. |
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2. | Delayed DECON - similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of decommissioning activities. Spent fuel is retained in existing location (either wet or dry storage) until DOE acceptance for disposal. |
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3. | Shortened SAFSTOR - similar to the DECON scenario but with generally a 30-year delay prior to onset of decommissioning activities. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal. |
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4. | SAFSTOR - a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60 years after cessation of operations. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
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The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location
and develop the necessary infrastructure for long-term SNF storage. For moreadditional information regarding the estimated date that DOE will begin accepting SNF, see Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
License Renewals
Except for its Clinton unit, Generation has successfully obtained initial 20-year operating license renewal extensions (i.e., extending the total license term to 60 years) for all of its operating nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG). Generation intends to apply for an initial license renewal for the Clinton unit. Clinton depreciation provisions are based on 2027 which is the last year of the Illinois Zero Emissions Standard. No prior Generation initial license extension application has been denied. Generation intends to apply for a second 20-year renewal for the Peach Bottom Units 2 and 3.
Discount Rates
Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. The authoritative guidance required Generation to establishinitially recognizes an ARO at fair value at the time of the initial adoption. Subsequent to the initial adoption, the ARO is adjustedand subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions, as described above.assumptions. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $9.7$10.0 billion to approximately $10.3$10.1 billion.
To illustrateThe following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: i) had Generation used the 2016 CARFR rather than the 2017 CARFRARO (dollars in performing its annual 2017 millions):
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Change in the CARFR applied to the annual ARO update | Increase (Decrease) to ARO at December 31, 2018 |
2017 CARFR rather than the 2018 CARFR | $ | 50 |
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2018 CARFR increased by 50 basis points | (100 | ) |
2018 CARFR decreased by 50 basis points | 130 |
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ARO update, Generation would have increased the ARO by an additional $10 million; and ii) if the CARFR
used in performing the annual 2017 ARO update are increased by 50 basis points or decreased by 50 basis points, the ARO would have decreased by $170 million and increased by $30 million, respectively, as compared to the actual decrease of $69 million.
ARO Sensitivities
Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):
| | Change in ARO Assumption | Increase (Decrease) to ARO at December 31, 2017 | Increase to ARO at December 31, 2018 |
Cost escalation studies | | |
Uniform increase in escalation rates of 50 basis points | $ | 1,690 |
| $ | 1,530 |
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Probabilistic cash flow models | | |
Increase the estimated costs to decommission the nuclear plants by 10 percent | 700 |
| 650 |
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Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the SAFSTOR scenario by 10 percentage points | 500 |
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Shorten each unit's probability weighted operating life assumption by 10%(a) | 660 |
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Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent(a) | | 410 |
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Shorten each unit's probability weighted operating life assumption by 10 percent(b) | | 720 |
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Extend the estimated date for DOE acceptance of SNF to 2035 | 130 |
| 90 |
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(a) | Timing sensitivity does not includeExcludes any sites in which management has committed to a specific decommissioning approach. |
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(b) | Excludes any retired site or sites for which an early plant retirement has been announced. |
For more information regarding accounting for nuclear decommissioning obligations, seeSee Note 1 — Significant Accounting Policies, Note 8 — Early Nuclear Plant Retirements and Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements.
Statements for additional information regarding accounting for nuclear decommissioning obligations.
Goodwill (Exelon, Generation, ComEd PHI and DPL)PHI)
As of December 31, 2017,2018, Exelon’s $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd, relating to the acquisition of ComEd in 2000 as part of the formation of Exelon and $4 billion at PHI pursuant to Exelon's acquisition of PHI in the first quarter of 2016. DPL has $8 million of goodwill as of December 31, 2017, related to its 1995 acquisition of the Conowingo Power Company.and immaterial amounts at Generation also has goodwill of $47 million as of December 31, 2017. Under the provisions of the authoritative guidance for goodwill, theseand DPL. These entities are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances
change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Under the authoritative guidance, aA reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL and ACE. See Note 25Note��24 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPLExelon's and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon’s and ComEd’s $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon’sunit. Exelon's and PHI’s $4 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $1.7$2.1 billion, $1.1$1.4 billion and $1.2$0.5 billion, respectively. DPL's $8 millionSee Note 10 — Intangible Assets of goodwill is assigned entirelythe Combined Notes to the DPL reporting unit.Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing aAs part of the qualitative assessment, entities should assess,assessments, Exelon, ComEd and PHI evaluate, among other things, macroeconomicmanagement's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, industryincluding the discount rate and market considerations including regulatoryregulated utility peer EBITDA multiples, and political developments, overall financial performance, cost factors, and entity-specific conditions and events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If an entity bypasses the qualitative assessment, or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than its carrying amount, apassing margin from their last quantitative two-step, fair value-based test isassessments performed.
Exelon’s, ComEd’s and PHI’s accounting policy is to perform a quantitative test of goodwill at least once every three years, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount. The first step in the quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. In January 2017, the FASB issued a new standard, effective January 1, 2020 with early adoption permitted, that simplifies the accounting for goodwill impairment by removing the second step of the test and, instead, measuring goodwill impairment at the amount by which a reporting unit's carrying value exceeds its fair value (currently the first step in the test). Exelon, Generation, ComEd, PHI and DPL have not determined whether to early adopt this standard.
Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates,
utility sector market performance and transactions, projected operating and capital cash flows for ComEd’s, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.
For their 2017 annual goodwill impairment assessments, Exelon, ComEd, PHI and DPL each qualitatively determined that it was more likely than not that the fair value of their respective reporting unit exceeded their respective carrying value. Therefore, ComEd, PHI and DPL did not perform quantitative assessments. As part of their qualitative assessments, ComEd, PHI and DPL evaluated, among other things, management's best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed as of November 1, 2016.
ComEd, PHI and DPL performed quantitative tests as of November 1, 2016, for their 2016 annual goodwill impairment assessments. The first step of the tests comparing the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second steps were required.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair valuesin the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's PHI’s or DPL’sPHI’s goodwill, which could be material. Based on the results of the last annual quantitative goodwill tests performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%30%, 10%20% and 10%30%, respectively, for Exelon, ComEd and PHI to have failedfail the first step of their respective impairment tests. For the $8 million of goodwill recorded at DPL related to DPL’s 1995 acquisition of the Conowingo Power Company, the fair value of the DPL reporting unit would have needed to decrease by more than 50% for DPL to fail the first step of the impairment test.
See Note 1 — Significant Accounting Policies and Note 10 — Intangible Assets and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Purchase Accounting (Exelon, Generation and PHI)
In January 2017, the FASB issued a new standard, effective January 1, 2018 with early adoption permitted, that clarifies the definition of a business with the objective of addressing whether acquisitions/dispositions should be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. The Registrants did not early adopt this new standard. See Note 1-Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for further information.
In accordance with authoritative guidance, the assetsAssets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. Authoritative guidance provides that theThe allocation of the purchase price may be modified up to one year after the
acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwill or bargain purchase gain would be recorded. See Note 45 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation and PHI)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has acquired and the electricity contracts Exelon has acquired as part of the PHI acquisition.merger. The initial amount recorded represents the fair value of the contracts at the time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded.recorded for those energy contract costs that are probable of recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.Amortization of the unamortized energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the underlying contract. Refer toSee Note 34 — Regulatory Matters, Note 45 — Mergers, Acquisitions and Dispositions and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for further discussion.additional information.
Impairment of Long-lived Assets (All Registrants)
All Registrants regularly monitor and evaluate their long-lived assets and asset groups, excluding goodwill, for impairment when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time, specific regulatory disallowance, advances in technology, or plans to dispose of a long-lived asset significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could have a significant impact onin the consolidated financial statements. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market discount rates.
Events and circumstances often do not occur as expected and there will usually be differences between prospective financial information and actual results, and those differences may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as information from various public, financial and industry sources.
Generation evaluates its equity method investments and other investments in debt and equity securities to determine whether or not they are impaired based on whether the investment has experienced a decline in value that is not temporary in nature. Beginning January 1, 2018, the authoritative guidance eliminates the available-for-sale and cost method classifications for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist. If the fair value is less than the carrying value, the impairment is recorded through earnings immediately in the period in which it is identified without regard to whether the decline in value is temporary in nature. The new authoritative guidance does not impact the classification or measurement of investments in debt securities. See Note 1-Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for further information.
See Note 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment evaluations made by Exelon.
Depreciable Lives of Property, Plant and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets are generally depreciated on a straight-line basis, using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have
approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is necessary.
For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs. Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL and ACE includes an estimated costestimate of the future costs of dismantling and removing plant from service upon retirement. Actual incurredSee Note 4 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL and ACE related to removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs.
PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. See Note 8 — Early Nuclear Plant
Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on expected and potential early nuclear plant retirements.
Generation completed a depreciation rate study during the first quarter of 2015, which resulted in revised depreciation rates effective January 1, 2015.
ComEd is required to file an electric distribution depreciation rate study at least every five years with the ICC. ComEd completed an electric distribution and transmission depreciation study and filed the updated depreciation rates with both the ICC and FERC in January 2014, resulting in new depreciation rates effective first quarter 2014.
PECO is required to file electric distribution and gas depreciation rate studies at least every five years with the PAPUC. In March 2015, PECO filed a depreciation rate study with the PAPUC for both its electric distribution and gas assets, resulting in new depreciation rates for electric transmission assets effective January 1, 2015, for gas distribution assets effective July 1, 2015, and for electric distribution assets effective January 1, 2016.
The MDPSC does not mandate the frequency or timing of BGE’s electric distribution or gas depreciation studies. In July 2014, BGE filed revised depreciation rates with the MDPSC for both its electric distribution and gas assets, which became effective December 15, 2014. In addition, BGE’s electric transmission depreciation rates were updated effective April 1, 2015.
The MDPSC does not mandate the frequency or timing of Pepco's electric distribution depreciation studies, while the DCPSC directs Pepco as to when it should file an electric distribution depreciation study. In 2016 and 2013, Pepco filed revised electric distribution depreciation rates with the MDPSC and DCPSC, respectively, with the new rates effective November 15, 2016 and April 16, 2014, respectively. On December 19, 2017, Pepco filed an electric distribution rate application which included revised depreciation rates. Pepco expects a decision in the fourth quarter of 2018.
Neither the DPSC nor the MDPSC mandates the frequency or timing of DPL's electric distribution or gas depreciation studies. On July 20, 2016, DPL filed revised electric depreciation rates with the MDPSC as part of the electric distribution base rate filing, resulting in new depreciation rates effective on April 20, 2017. On May 17, 2016, DPL filed revised electric and natural gas depreciation rates with the DPSC as part of the electric and natural gas base rate case filing, resulting in new electric depreciation rates effective June 1, 2017 and new gas depreciation rates effective July 1, 2017.
The NJBPU does not mandate the frequency or timing of ACE's electric distribution depreciation studies. In 2012, ACE filed revised electric distribution depreciation rates with the NJBPU, with the new rates effective July 1, 2013. ACE expects to perform an electric distribution depreciation study in 2018.
While FERC does not mandate the frequency or timing of electric transmission depreciation studies, the Utility Registrants and Generation perform studies on all assets every 5 years. Pepco, DPL and ACE last performed transmission depreciation studies in 1988, 1990, and 2003, respectively, but are adopting Exelon's practice and are currently evaluating the timing of the next study.information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated service lives of the property, plant and equipment of the Registrants.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement employee benefit plans for substantially all current employees. See Note 16 — Retirement Benefits of the Combined Notes to
Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans.
The measurement of the plan obligations and costs of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is affected by several assumptions including the discount rate applied to benefit obligations, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, Exelon’s expected level of contributions to the plans, the incidence of participant mortality, the expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants. Pension and other postretirement benefit costs attributed to the operating companies are labor costs and are ultimately allocated to projects within the operating companies, some of which are capitalized.
Pension and other postretirement benefit plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain alternative investment classes such as real estate, private equity and hedge funds. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and other postretirement plan assets, including valuation techniques and classification under the fair value hierarchy in accordance with authoritative guidance.
Expected Rate of Return on Plan Assets
Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations. Exelon calculates the amount of expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated
value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s EROA assumptions.
Discount Rate
Rate. At December 31, 20172018 and 2016,2017, the discount rates were determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable (or callable with make whole provisions) bonds with similar maturities to the related pension and other postretirement benefit obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefit plans. The discount rate is the single level rate that produces the same result as the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon’s discount rate assumptions.
Health Care Cost Trend Rate
Assumed health care cost trend rates impact the costs reported for Exelon’s other postretirement benefit plans for participant populations with plan designs that do not have a cap on cost growth. Authoritative guidance requires that annual health care cost estimates be developed using past and present health care cost trends (both for Exelon and across the broader economy), as well as expectations of health care cost escalation, changes in health care utilization and delivery patterns, technological advances and changes in the health status of plan participants. Therefore, the trend rate assumption is subject to significant uncertainty. Exelon assumes an ultimate health care cost trend rate of 5.00% has been reached in 2017 for its other postretirement benefit plans.
Mortality
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption is supported by an actuarial experience study of Exelon's plan participants and utilizes the IRS's RP-2000 base table and the Scale BB 2-Dimensional improvement scale with long-term improvements of 0.75%.
Sensitivity to Changes in Key Assumptions
Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above, while holding all other assumptions constant (dollars in millions):
| | | Actual Assumption | | | | | | | Actual Assumption | | | | | | |
Actuarial Assumption | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total | Pension | | OPEB | | Change in Assumption | | Pension | | OPEB | | Total |
Change in 2017 cost: | | | | | | | |
Change in 2018 cost: | | | | | | | |
Discount rate (a) | 4.04% | | 4.04% | | 0.5% | | $ | (72 | ) | | $ | (16 | ) | | $ | (88 | ) | 3.62% | | 3.61% | | 0.5% | | $ | (51 | ) | | $ | (17 | ) | | $ | (68 | ) |
| 4.04% | | 4.04% | | (0.5)% | | 89 |
| | 19 |
| | 108 |
| 3.62% | | 3.61% | | (0.5)% | | 62 |
| | 21 |
| | 83 |
|
EROA | 7.00% | | 6.58% | | 0.5% | | (85 | ) | | (12 | ) | | (97 | ) | 7.00% | | 6.60% | | 0.5% | | (90 | ) | | (13 | ) | | (103 | ) |
| 7.00% | | 6.58% | | (0.5)% | | 85 |
| | 12 |
| | 97 |
| 7.00% | | 6.60% | | (0.5)% | | 89 |
| | 13 |
| | 102 |
|
Health care cost trend rate | NA | | 5.00% | | 1.00% | | N/A |
| | 9 |
| | 9 |
| |
| NA | | 5.00% | | (1.00)% | | N/A |
| | (8 | ) | | (8 | ) | |
Change in benefit obligation at December 31, 2017: | | | | | | | |
Change in benefit obligation at December 31, 2018: | | | | | | | |
Discount rate (a) | 3.62% | | 3.61% | | 0.5% | | (1,183 | ) | | (252 | ) | | (1,435 | ) | 4.31% | | 4.30% | | 0.5% | | (1,180 | ) | | (246 | ) | | (1,426 | ) |
| 3.62% | | 3.61% | | (0.5)% | | 1,371 |
| | 291 |
| | 1,662 |
| 4.31% | | 4.30% | | (0.5)% | | 1,371 |
| | 284 |
| | 1,655 |
|
Health care cost trend rate | NA | | 5.00% | | 1.00% | | N/A |
| | 125 |
| | 125 |
| |
| NA | | 5.00% | | (1.00)% | | N/A |
| | (113 | ) | | (113 | ) | |
__________
| |
(a) | In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the discount rate sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns. |
See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension plans and other postretirement benefit plans.
Regulatory Accounting (Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)Utility Registrants)
Exelon and the Utility Registrants account forFor their regulated electric and gas operations, in accordance with the authoritative guidance, which requires Exelon and the Utility Registrants to reflect the effects of cost-based rate regulation in their financial statements. This authoritative guidancestatements, which is
applicable to required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. As of December 31, 2017, Exelon and the Utility Registrants have concluded that the operations of each such Registrant meet the criteria to apply the authoritative guidance. If it is concluded in a future period that a separable portion of operations no longer meets the criteria of this authoritative guidance,discussed above, Exelon and the Utility Registrants would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the Consolidated Statements of Operations and Comprehensive Income and could be material. At December 31, 2017,
The following table illustrates the gain (loss)gains (losses) that could have been as much as $1.1 billion, $5.3 billion, $280 million, $592 million, $(1.1) billion, $(59) million, $321 million and $(8) million (before taxes) as a result offrom the elimination of regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively. Further, Exelon would record a chargecharges against OCI (before(dollars in millions before taxes) of up to $3.8 billion, $2.4 billion, $544 million,$177 million, $407 million, $202 million and $92 million related to Exelon's, ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans that are recorded as regulatory assets onin Exelon's Consolidated Balance Sheets. Exelon also has a net regulatory liability of $(31) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would result in an increase in OCI if reversed. Sheets:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Gain (loss) | $ | 744 |
| | $ | 4,743 |
| | $ | 55 |
| | $ | 694 |
| | $ | (853 | ) | | $ | (84 | ) | | $ | 375 |
| | $ | (6 | ) |
Charge against OCI(a) | $ | 3,754 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
___________
| |
(a) | Exelon's charge against OCI (before taxes) consists of up to $2.4 billion, $529 million, $157 million, $413 million, $208 million and $105 million related to ComEd's, BGE's, PHI's, Pepco's, DPL's and ACE's respective portions of the deferred costs associated with Exelon's pension and other postretirement benefit plans. Exelon also has a net regulatory liability of $(47) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would result in an increase in OCI if reversed. |
See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including the regulatory assets and liabilities tables of Exelon and the Utility Registrants.
For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in applicable regulatory and political environments. Furthermore, each Registrant makes other judgments related toIf the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statement impact of their regulatory environments, such as the types of adjustments to rate base that willstatements could be acceptable to regulatory bodies, if any, for which costs will be recoverable through rates. material.
Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for ComEd, PECO, BGE, Pepco, DPL and ACE. Additionally, estimates are made in accordance with the authoritative guidance for contingencies as to the amount of revenues billed under certain regulatory orders that may ultimately be refunded to customers upon finalization of applicable regulatory or judicial processes. These assessments are based, to the extent possible, on past relevant experience with regulatory bodies in each Registrant's jurisdictions, known circumstances specific to a particular matter and hearings held with the applicable regulatory body. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and regulatory liabilities are ultimately different than actual regulatory outcomes, the impact on their results of operations, cash flows and financial positions could be material.
The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Registrants.
Accounting for Derivative Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.information.
The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlyings and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope to new authoritative guidance. Generation has determined that contracts to purchase uranium, contracts to purchase and sell capacity in certain ISO’s, certain emission products, ZECs and RECs do not meet the definition of a derivative as they do not provide for net settlement and the uranium, certain capacity, emission and ZEC and REC markets are not sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. If these markets become sufficiently liquid, then Generation would be required to account for these contracts as derivative instruments. In this case, if market prices differ from the underlying prices of the contracts, Generation would be required to record mark-to-market gains or losses, which could have a material impact to Exelon’s and Generation’s results of operations and financial positions.
Under current authoritative guidance, all derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, the normal purchases and normal sales exception. Further, derivatives that qualifyDerivatives entered into for economic hedging and are designated for hedge accounting are classified as either fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings immediately. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in AOCI and reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. The Registrants rarely elect hedge accounting for commodity transactions. Economic commodity hedgesproprietary trading purposes are recorded at fair value through earnings. In addition, for commodity derivatives executed for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings immediately. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting regulatory asset or liability given likelihood of recovering the associated costs through customer rates.
Normal Purchases and Normal Sales Exception
Exception. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under the authoritative guidance, certain of these qualifying transactions have been designated by Generation as normal purchases and normal sales transactions, which are thus not required to be
recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the normal purchases and normal sales exception requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation requirements. Revenues and expenses on contracts that qualify as normal purchases and normal sales are recognized when the underlying physical transaction is completed. Contracts that qualify for the normal purchases and normal sales exception
are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives and certain Pepco, DPL and ACE full requirement contracts qualify for and are accounted for under the normal purchases and normal sales exception.
Commodity Contracts
Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.
As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, the model inputs are generally observable. Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the financial statements.
Interest Rate and Foreign Exchange Derivative Instruments
Instruments. The Registrants may utilize fixed-to-floating interest rate swaps which are typically designated as fair value hedges, to achieve the targeted level of variable-rate debt as a percent of total debt. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest-rate levels and floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the economic hedge and proprietary trading activity is driven by the corresponding characterization of the underlying
commodity position that gives rise to the interest rate exposure. Generation does not utilize interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. The fair value of the agreements is calculated by discounting the future net cash flows to the present value based on observable inputs and are primarily categorized in Level 2 in the fair value hierarchy. Certain exchange based interest rate derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 11 — Fair Value of Financial Assets and Liabilities and Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. In accordance with applicable authoritative guidance, theThe Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. Management evaluates each position based solely on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also evaluate forassess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets, such as historical operating loss or tax credit carryforward expiration.assets. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when they conclude it is more-likely-than-not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. The Registrants have recorded the provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for which the impacts could not be finalized upon issuance of the Registrants' financial statements, but for which reasonable estimates could be determined. In accordance with SAB 118, additional remeasurement may occur based on technical corrections or other forms of guidance issued, which may result in material changes to previously finalized provisions. While the Registrants believe the resulting tax balances as of December 31, 2017 and 2016 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of tax matters could result in favorable or unfavorable adjustments that could be material to their consolidated financial statements. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.
information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference could have a significant impact onin the Registrants' consolidated financial statements.
Environmental Costs
Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work and changes in technology, regulations and the requirements of local governmental authorities. PeriodicAnnual studies and/or reviews are conducted at the Utility RegistrantsComEd, PECO, BGE and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner different from the estimate, could have a significant impact onin the Registrants’ results of operations, cash flows andconsolidated financial positions.statements. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for furtheradditional information.
Other, Including Personal Injury Claims
Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact onin the Registrants’ results of operations, cash flows andconsolidated financial positions.statements.
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment
Treatment. The Registrants earn revenues from various business activities including: the sale of energypower and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery of electricitypower and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants primarily use accrual, mark-to-market,apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP) accountingguidance to recognize revenue as discussed in more detail below. Beginning on January 1, 2018, the Registrants will begin applying
Revenue from Contracts with Customers. Under the Revenue from Contracts with Customers guidance, to recognize revenue. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
Accrual Accounting
Under accrual accounting, the Registrants recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when services are rendered or energy is delivered to customers. The Registrants generally use accrual accounting to recognize revenues for sales of electricity,power, natural gas, and other energy-related commodities as partare physically delivered to the customer. Transactions of their physical delivery activities. Thethe Registrants enter into these sales transactions using a varietywithin the scope of instruments,
includingRevenue from Contracts with Customers generally include non-derivative agreements, derivativescontracts that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities that will be physically delivered,, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with independent system operators.
The determination of Generation'sGeneration’s and the Utility Registrants' energyretail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer usage measured by energygeneration or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer rates. Increases or decreases in volumes delivered to the utilities'utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in customerscustomer classes in the period could be significant to the calculation of unbilled revenue. In addition, unbilled revenues may fluctuate monthly as a result of customers electing to use an alternate supplier, since unbilled commodity receivablesrevenues are not recorded for these customers. Changes in the timing of meter reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue,revenue; however, total operating revenues would remain materially unchanged. See Note 51 — Accounts ReceivableSignificant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information on unbilled revenue.information.
Mark-to-Market Accounting
Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that meet the definition of aare accounted for as derivatives. These derivative for which they are not permitted, or have not elected, the NPNS exception. These mark-to-market transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses include: inception gains or losses on new transactions where the fair value is observable, and realized; and unrealized gains and losses from changes in the fair value of open contracts.contracts, and realized gains and losses.
Alternative Revenue Program Accounting
Accounting. Certain of the Utility Registrants'Registrants’ ratemaking mechanisms qualify as ARPsAlternative Revenue Programs (ARPs) if they (i) are established by a regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months following the end of the period in which they were recognized. For mechanisms that meet certain criteria. At each balance sheet date,these criteria, which include the Utility Registrants’ formula rate and revenue decoupling mechanisms, the Utility Registrants with such mechanisms, including ComEd's electric distribution and energy efficiency formulas, and ComEd's, PECO's, BGE's, Pepco's, DPL's, and ACE's FERC transmission formula rates, record ARP revenues for any differences between the prior yearadjust revenue requirement in effect in rates and their best estimate of the current year revenue requirement that is probable of approval by the ICC or FERC. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investment in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. ComEd, BGE, Pepco, and DPL also have decoupling mechanisms which qualify as ARPs. The Utility Registrants recognize and record an offsetting regulatory asset or liability once the condition or event allowing foradditional billing or refund has occurred. The ARP revenues presented in the automatic adjustment of future rates occurs.
The Utility Registrants’ ARP revenuesConsolidated Statements of Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of approval by FERC in
accordance with their formula rate mechanisms. Estimates of the current year revenue requirement are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred, investments made, allowed ROE, and actions by regulators or courts.
See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for furtheradditional information.
Allowance for Uncollectible Accounts (All(Utility Registrants)
The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. ComEd, PECO, BGE, Pepco, DPL and ACE,Utility Registrants estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are comprised based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU regulations. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information regarding accounts receivable.
Results of Operations by Business SegmentRegistrant
The comparisonsRegistrants' Results of operating resultsOperations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other statisticalcompanies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation evaluate the years ended December 31, 2017, 2016performance of Generation's electric business activities and 2015 set forth below include intercompany transactions,allocate resources based on RNF. Generation believes that RNF is a useful measure because it provides information that can be used to evaluate its operational performance. For the Utility Registrants, their Operating revenues reflect the full and current recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which are eliminatedrecorded in Exelon’s consolidated financial statements.
Net Income (Loss) Attributable to Common ShareholdersPurchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful measure because it excludes the effect on Operating revenues caused by Registrant
|
| | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Favorable (unfavorable) 2017 vs. 2016 variance | | For the Year Ended December 31, 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance |
| 2017 | | 2016 | | | |
Exelon | $ | 3,770 |
| | $ | 1,134 |
| | $ | 2,636 |
| | $ | 2,269 |
| | $ | (1,135 | ) |
Generation | 2,694 |
| | 496 |
| | 2,198 |
| | 1,372 |
| | (876 | ) |
ComEd | 567 |
| | 378 |
| | 189 |
| | 426 |
| | (48 | ) |
PECO | 434 |
| | 438 |
| | (4 | ) | | 378 |
| | 60 |
|
BGE | 307 |
| | 286 |
| | 21 |
| | 275 |
| | 11 |
|
Pepco | 205 |
| | 42 |
| | 163 |
| | 187 |
| | (145 | ) |
DPL | 121 |
| | (9 | ) | | 130 |
| | 76 |
| | (85 | ) |
ACE | 77 |
| | (42 | ) | | 119 |
| | 40 |
| | (82 | ) |
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
| | $ | 327 |
|
the volatility in these expenses.
Results of Operations—Generation
| | | 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 18,466 |
| | $ | 17,751 |
| | $ | 715 |
| | $ | 19,135 |
| | $ | (1,384 | ) | $ | 20,437 |
| | $ | 18,500 |
| | $ | 1,937 |
| | $ | 17,757 |
| | $ | 743 |
|
Purchased power and fuel expense | 9,690 |
| | 8,830 |
| | (860 | ) | | 10,021 |
| | 1,191 |
| 11,693 |
| | 9,690 |
| | (2,003 | ) | | 8,830 |
| | (860 | ) |
Revenues net of purchased power and fuel expense(a) | 8,776 |
|
| 8,921 |
| | (145 | ) |
| 9,114 |
|
| (193 | ) | 8,744 |
|
| 8,810 |
| | (66 | ) |
| 8,927 |
|
| (117 | ) |
Other operating expenses | | | | |
|
| | | | | | | | |
|
| | | | |
Operating and maintenance | 6,291 |
| | 5,641 |
| | (650 | ) | | 5,308 |
| | (333 | ) | 5,464 |
| | 6,299 |
| | 835 |
| | 5,663 |
| | (636 | ) |
Depreciation and amortization | 1,457 |
| | 1,879 |
| | 422 |
| | 1,054 |
| | (825 | ) | 1,797 |
| | 1,457 |
| | (340 | ) | | 1,879 |
| | 422 |
|
Taxes other than income | 555 |
| | 506 |
| | (49 | ) | | 489 |
| | (17 | ) | 556 |
| | 555 |
| | (1 | ) | | 506 |
| | (49 | ) |
Total other operating expenses | 8,303 |
|
| 8,026 |
| | (277 | ) |
| 6,851 |
|
| (1,175 | ) | 7,817 |
|
| 8,311 |
| | 494 |
|
| 8,048 |
|
| (263 | ) |
Gain (Loss) on sales of assets | 2 |
| | (59 | ) | | 61 |
| | 12 |
| | (71 | ) | |
Gain (loss) on sales of assets and businesses | | 48 |
| | 2 |
| | 46 |
| | (59 | ) | | 61 |
|
Bargain purchase gain | 233 |
| | — |
| | 233 |
| | — |
| | — |
| — |
| | 233 |
| | (233 | ) | | — |
| | 233 |
|
Gain on deconsolidation of business | 213 |
| | — |
| | 213 |
| | — |
| | — |
| — |
| | 213 |
| | (213 | ) | | — |
| | 213 |
|
Operating income | 921 |
|
| 836 |
|
| 85 |
|
| 2,275 |
|
| (1,439 | ) | 975 |
|
| 947 |
|
| 28 |
|
| 820 |
|
| 127 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | | |
Interest expense | (440 | ) | | (364 | ) | | (76 | ) | | (365 | ) | | 1 |
| (432 | ) | | (440 | ) | | 8 |
| | (364 | ) | | (76 | ) |
Other, net | 948 |
| | 401 |
| | 547 |
| | (60 | ) | | 461 |
| (178 | ) | | 948 |
| | (1,126 | ) | | 401 |
| | 547 |
|
Total other income and (deductions) | 508 |
|
| 37 |
|
| 471 |
|
| (425 | ) |
| 462 |
| (610 | ) |
| 508 |
|
| (1,118 | ) |
| 37 |
|
| 471 |
|
Income before income taxes | 1,429 |
|
| 873 |
|
| 556 |
|
| 1,850 |
|
| (977 | ) | 365 |
|
| 1,455 |
|
| (1,090 | ) |
| 857 |
|
| 598 |
|
Income taxes | (1,375 | ) | | 290 |
| | 1,665 |
| | 502 |
| | 212 |
| (108 | ) | | (1,376 | ) | | (1,268 | ) | | 282 |
| | 1,658 |
|
Equity in losses of unconsolidated affiliates | (33 | ) | | (25 | ) | | (8 | ) | | (8 | ) | | (17 | ) | (30 | ) | | (33 | ) | | 3 |
| | (25 | ) | | (8 | ) |
Net income | 2,771 |
|
| 558 |
|
| 2,213 |
|
| 1,340 |
|
| (782 | ) | 443 |
|
| 2,798 |
|
| (2,355 | ) |
| 550 |
|
| 2,248 |
|
Net income (loss) attributable to noncontrolling interests | 77 |
| | 62 |
| | 15 |
| | (32 | ) | | 94 |
| |
Net income attributable to noncontrolling interests | | 73 |
| | 88 |
| | (15 | ) | | 67 |
| | 21 |
|
Net income attributable to membership interest | $ | 2,694 |
|
| $ | 496 |
|
| $ | 2,198 |
|
| $ | 1,372 |
|
| $ | (876 | ) | $ | 370 |
|
| $ | 2,710 |
|
| $ | (2,340 | ) |
| $ | 483 |
|
| $ | 2,227 |
|
__________ Year Ended December 31, 2018 Compared to Year Ended December 31, 2017. Net income attributable to membership interest decreased by $2,340 million primarily due to:
| |
(a) | Generation evaluates its operating performance using the measure of revenues net of purchased power and fuel expense. Generation believes that revenues net of purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues 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. |
Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;
The gain associated with the FitzPatrick acquisition in 2017;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017; and
Long-lived asset impairments of certain merchant wind assets in West Texas.
The decreases were partially offset by;
The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net Income Attributable to Membership Interestrealized gains on NDT funds; and
Decreased nuclear outage days.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Generation's Net income attributable to membership interest increased compared to the same period in 2016,by $2,227 million primarily due to lower Depreciation and amortization, a Bargain purchase gain in 2017, a Gain on deconsolidationto:
Impacts associated with the one-time remeasurement of business in 2017, higher Otherdeferred income and decreased Income taxes partially offset by lower Revenues net of purchased power and fuel expense and higher Operating and maintenance expense. The decrease in Depreciation and amortization expense is primarily due to lower accelerated depreciation and amortization as a result of the 2017TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016 to early retire the Clinton and Quad Cities nuclear facilities. facilities;
Higher net unrealized and realized gains on NDT funds;
The Bargain purchaseimpact of the New York ZEC revenue;
The gain is duerecorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices; and
Decreased nuclear outage days.
These increases were partially offset by:
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility. The Gain on deconsolidation of business in 2017 is due to the deconsolidation of EGTP's net liabilities, which included the previously impaired assetsfacility; and related debt, as a result of the November 2017 bankruptcy filing. The increase in Other income is primarily due to higher realized NDT fund gains. The decrease in Income taxes primarily relates to the one-time non-cash impacts associated with the Tax Cuts and Jobs Act. The decrease in Revenues net of purchased power and fuel expense primarily reflects lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation’s natural gas portfolio, partially offset by the impact of the New York CES, higher capacity prices, the addition of two combined-cycle gas turbines in Texas and lower nuclear fuel prices. The increase in Operating and maintenance expense is primarily related to the impairment of EGTP in 2017.
Increased mark-to-market losses.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.Generation's Net income attributable to membership interest decreased compared to the same period in 2015, primarily due to lower Revenues net of purchased power and fuel expense, higher Operating and maintenance expense, higher Depreciation and amortization expense, and Losses on sales of assets in 2016, partially offset by increased Other income and decreased Income tax expense. The decrease in Revenues net of purchased power and fuel expense primarily relates to lower mark-to-market results in 2016 compared to 2015 and lower realized energy prices, partially offset by the Ginna Reliability Support Services Agreement and a decrease in outage days at higher capacity units despite an increase in overall outage days. The increase in Operating and maintenance expense is primarily related to the impairment of Upstream assets and certain wind projects, and increased costs related to the implementation of the cost management program. The increase in Depreciation and amortization expense is primarily related to accelerated depreciation and amortization expense related to the previous 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 Losses on sales of assets is primarily due to Generation's strategic decision to narrow the scope and scale of its growth and development activities. The increase in Other income is primarily due to the change in realized and unrealized gains and losses on NDT funds.
Revenues Net of Purchased Power and Fuel Expense
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’sGeneration's six reportable segments are Mid-Atlantic, Midwest, New England, ERCOT and Other Power Regions. During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as follows:
Mid-Atlantic represents operationsa separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the eastern halffirst quarter of PJM, which includes2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of ColumbiaYork, ERCOT 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 within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering mostOther Power Regions. See Note 24 - Segment Information of the state of Texas.
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 the AESO, OIESO and the Canadian portion of MISO.
Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.The following business activities are not allocated to a region, and are reported under Other: natural gas, as well as other miscellaneous business activities that are not significant to 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 electric business activities using the measure of Revenue net of purchased power and fuel expense, which is a non-GAAP measurement. Generation’s operatingRNF. Operating revenues include all sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.
For the years ended December 31, 2018 compared to 2017 and December 31, 2017 compared to 2016, and December 31, 2016 compared to 2015, Generation’s Revenue net of purchased power and fuel expenseRNF by region were as follows:
| | | | | | | 2017 vs. 2016 | | | | 2016 vs. 2015 | | | | | 2018 vs. 2017 | | | | 2017 vs. 2016 |
| 2017 | | 2016 | | Variance | | % Change | | 2015 | | Variance | | % Change | 2018 | | 2017 | | Variance | | % Change | | 2016 | | Variance | | % Change |
Mid-Atlantic(a) | $ | 3,214 |
| | $ | 3,317 |
| | $ | (103 | ) | | (3.1 | )% | | $ | 3,571 |
| | $ | (254 | ) | | (7.1 | )% | $ | 3,073 |
| | $ | 3,214 |
| | $ | (141 | ) | | (4.4 | )% | | $ | 3,317 |
| | $ | (103 | ) | | (3.1 | )% |
Midwest(b)(a) | 2,820 |
| | 2,971 |
| | (151 | ) | | (5.1 | )% | | 2,892 |
| | 79 |
| | 2.7 | % | 3,135 |
| | 2,820 |
| | 315 |
| | 11.2 | % | | 2,971 |
| | (151 | ) | | (5.1 | )% |
New England | 514 |
| | 438 |
| | 76 |
| | 17.4 | % | | 461 |
| | (23 | ) | | (5.0 | )% | 354 |
| | 514 |
| | (160 | ) | | (31.1 | )% | | 438 |
| | 76 |
| | 17.4 | % |
New York(d)(c) | 976 |
| | 742 |
| | 234 |
| | 31.5 | % | | 634 |
| | 108 |
| | 17.0 | % | 1,122 |
| | 1,008 |
| | 114 |
| | 11.3 | % | | 752 |
| | 256 |
| | 34.0 | % |
ERCOT | 332 |
| | 281 |
| | 51 |
| | 18.1 | % | | 293 |
| | (12 | ) | | (4.1 | )% | 258 |
| | 332 |
| | (74 | ) | | (22.3 | )% | | 281 |
| | 51 |
| | 18.1 | % |
Other Power Regions | 305 |
| | 336 |
| | (31 | ) | | (9.2 | )% | | 250 |
| | 86 |
| | 34.4 | % | 375 |
| | 305 |
| | 70 |
| | 23.0 | % | | 336 |
| | (31 | ) | | (9.2 | )% |
Total electric revenues net of purchased power and fuel expense | 8,161 |
|
| 8,085 |
|
| 76 |
| | 0.9 | % | | 8,101 |
|
| (16 | ) | | (0.2 | )% | 8,317 |
|
| 8,193 |
|
| 124 |
| | 1.5 | % | | 8,095 |
|
| 98 |
| | 1.2 | % |
Proprietary Trading | 18 |
| | 15 |
| | 3 |
| | n.m. |
| | 1 |
| | 14 |
| | n.m. |
| 42 |
| | 18 |
| | 24 |
| | n.m. |
| | 15 |
| | 3 |
| | n.m. |
|
Mark-to-market gains (losses) | (175 | ) | | (41 | ) | | (134 | ) | | 326.8 | % | | 257 |
| | (298 | ) | | (116.0 | )% | |
Mark-to-market losses | | (319 | ) | | (175 | ) | | (144 | ) | | 82.3 | % | | (41 | ) | | (134 | ) | | 326.8 | % |
Other(c)(b) | 772 |
| | 862 |
| | (90 | ) | | (10.4 | )% | | 755 |
| | 107 |
| | 14.2 | % | 704 |
| | 774 |
| | (70 | ) | | (9.0 | )% | | 858 |
| | (84 | ) | | (9.8 | )% |
Total revenue net of purchased power and fuel expense | $ | 8,776 |
|
| $ | 8,921 |
|
| $ | (145 | ) | | (1.6 | )% | | $ | 9,114 |
|
| $ | (193 | ) | | (2.1 | )% | $ | 8,744 |
|
| $ | 8,810 |
|
| $ | (66 | ) | | (0.7 | )% | | $ | 8,927 |
|
| $ | (117 | ) | | (1.3 | )% |
_________
| |
(a) | ResultsIncludes results of transactions with PECO and BGE are included in the Mid-Atlantic region and results of transactions with ComEd in the Midwest region. ResultsAs a result of the PHI merger, includes results of transactions with Pepco, DPL and ACE are included in the Mid-Atlantic region beginning on March 24, 2016, the day after the PHI merger was completed.2016. |
| |
(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 $54 million decrease to RNF anand a $57 million decrease to RNF, and an $8 million increase to RNF for the years ended December 31, 2017 and 2016, and 2015, respectively, and accelerated nuclear fuel amortization associated with announced early plant retirements, as discussed in Note 8 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements, of $57 million, $12 million and $60 million for the years ended December 31, 2018, 2017 and 2016, respectively.respectively, and gain on the settlement of a long-term gas supply agreement of $75 million for the year ended December 31, 2018. |
| |
(d)(c) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Generation’s supply sources by region are summarized below:
| | | | | | | 2017 vs. 2016 | | | | 2016 vs. 2015 | | | | | 2018 vs. 2017 | | | | 2017 vs. 2016 |
Supply Source (GWh) | 2017 | | 2016 | | Variance | | % Change | | 2015 | | Variance | | % Change | |
Supply Source (GWhs) | | 2018 | | 2017 | | Variance | | % Change | | 2016 | | Variance | | % Change |
Nuclear Generation(a) | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mid-Atlantic | 64,466 |
| | 63,447 |
| | 1,019 |
| | 1.6 | % | | 63,283 |
| | 164 |
| | 0.3 | % | 64,099 |
| | 64,466 |
| | (367 | ) | | (0.6 | )% | | 63,447 |
| | 1,019 |
| | 1.6 | % |
Midwest | 93,344 |
| | 94,668 |
| | (1,324 | ) | | (1.4 | )% | | 93,422 |
| | 1,246 |
| | 1.3 | % | 94,283 |
| | 93,344 |
| | 939 |
| | 1.0 | % | | 94,668 |
| | (1,324 | ) | | (1.4 | )% |
New York(c) | 25,033 |
| | 18,684 |
| | 6,349 |
| | 34.0 | % | | 18,769 |
| | (85 | ) | | (0.5 | )% | 26,640 |
| | 25,033 |
| | 1,607 |
| | 6.4 | % | | 18,684 |
| | 6,349 |
| | 34.0 | % |
Total Nuclear Generation | 182,843 |
| | 176,799 |
| | 6,044 |
| | 3.4 | % | | 175,474 |
| | 1,325 |
| | 0.8 | % | 185,022 |
| | 182,843 |
| | 2,179 |
| | 1.2 | % | | 176,799 |
| | 6,044 |
| | 3.4 | % |
Fossil and Renewables | | | | | | |
|
| | | | | |
|
| | | | | | |
|
| | | | | |
|
|
Mid-Atlantic | 2,789 |
| | 2,731 |
| | 58 |
| | 2.1 | % | | 2,774 |
| | (43 | ) | | (1.6 | )% | 3,670 |
| | 2,789 |
| | 881 |
| | 31.6 | % | | 2,731 |
| | 58 |
| | 2.1 | % |
Midwest | 1,482 |
| | 1,488 |
| | (6 | ) | | (0.4 | )% | | 1,547 |
| | (59 | ) | | (3.8 | )% | 1,373 |
| | 1,482 |
| | (109 | ) | | (7.4 | )% | | 1,488 |
| | (6 | ) | | (0.4 | )% |
New England | 7,179 |
| | 6,968 |
| | 211 |
| | 3.0 | % | | 2,983 |
| | 3,985 |
| | 133.6 | % | 4,731 |
| | 7,179 |
| | (2,448 | ) | | (34.1 | )% | | 6,968 |
| | 211 |
| | 3.0 | % |
New York | 3 |
| | 3 |
| | — |
| | — | % | | 3 |
| | — |
| | — | % | 3 |
| | 3 |
| | — |
| | — | % | | 3 |
| | — |
| | — | % |
ERCOT | 12,072 |
| | 6,785 |
| | 5,287 |
| | 77.9 | % | | 5,763 |
| | 1,022 |
| | 17.7 | % | 11,180 |
| | 12,072 |
| | (892 | ) | | (7.4 | )% | | 6,785 |
| | 5,287 |
| | 77.9 | % |
Other Power Regions | 6,869 |
| | 8,179 |
| | (1,310 | ) | | (16.0 | )% | | 7,848 |
| | 331 |
| | 4.2 | % | 8,525 |
| | 6,869 |
| | 1,656 |
| | 24.1 | % | | 8,179 |
| | (1,310 | ) | | (16.0 | )% |
Total Fossil and Renewables | 30,394 |
|
| 26,154 |
| | 4,240 |
| | 16.2 | % | | 20,918 |
|
| 5,236 |
| | 25.0 | % | 29,482 |
|
| 30,394 |
| | (912 | ) | | (3.0 | )% | | 26,154 |
|
| 4,240 |
| | 16.2 | % |
Purchased Power | | | | | | |
|
| | | | | |
|
| | | | | | |
|
| | | | | |
|
|
Mid-Atlantic | 9,801 |
| | 16,874 |
| | (7,073 | ) | | (41.9 | )% | | 8,160 |
| | 8,714 |
| | 106.8 | % | 6,506 |
| | 9,801 |
| | (3,295 | ) | | (33.6 | )% | | 16,874 |
| | (7,073 | ) | | (41.9 | )% |
Midwest | 1,373 |
| | 2,255 |
| | (882 | ) | | (39.1 | )% | | 2,325 |
| | (70 | ) | | (3.0 | )% | 996 |
| | 1,373 |
| | (377 | ) | | (27.5 | )% | | 2,255 |
| | (882 | ) | | (39.1 | )% |
New England | 18,517 |
| | 16,632 |
| | 1,885 |
| | 11.3 | % | | 24,309 |
| | (7,677 | ) | | (31.6 | )% | 26,033 |
| | 18,517 |
| | 7,516 |
| | 40.6 | % | | 16,632 |
| | 1,885 |
| | 11.3 | % |
New York | 28 |
| | — |
| | 28 |
| | — | % | | — |
| | — |
| | — | % | — |
| | 28 |
| | (28 | ) | | — | % | | — |
| | 28 |
| | — | % |
ERCOT | 7,346 |
| | 10,637 |
| | (3,291 | ) | | (30.9 | )% | | 10,070 |
| | 567 |
| | 5.6 | % | 6,550 |
| | 7,346 |
| | (796 | ) | | (10.8 | )% | | 10,637 |
| | (3,291 | ) | | (30.9 | )% |
Other Power Regions | 14,530 |
| | 13,589 |
| | 941 |
| | 6.9 | % | | 18,773 |
| | (5,184 | ) | | (27.6 | )% | 18,965 |
| | 14,530 |
| | 4,435 |
| | 30.5 | % | | 13,589 |
| | 941 |
| | 6.9 | % |
Total Purchased Power | 51,595 |
| | 59,987 |
|
| (8,392 | ) | | (14.0 | )% | | 63,637 |
| | (3,650 | ) | | (5.7 | )% | 59,050 |
| | 51,595 |
|
| 7,455 |
| | 14.4 | % | | 59,987 |
| | (8,392 | ) | | (14.0 | )% |
Total Supply/Sales by Region | | | | | | |
|
| | | | | |
|
| | | | | | |
|
| | | | | |
|
|
Mid-Atlantic(b) | 77,056 |
| | 83,052 |
| | (5,996 | ) | | (7.2 | )% | | 74,217 |
| | 8,835 |
| | 11.9 | % | 74,275 |
| | 77,056 |
| | (2,781 | ) | | (3.6 | )% | | 83,052 |
| | (5,996 | ) | | (7.2 | )% |
Midwest(b) | 96,199 |
| | 98,411 |
| | (2,212 | ) | | (2.2 | )% | | 97,294 |
| | 1,117 |
| | 1.1 | % | 96,652 |
| | 96,199 |
| | 453 |
| | 0.5 | % | | 98,411 |
| | (2,212 | ) | | (2.2 | )% |
New England | 25,696 |
| | 23,600 |
| | 2,096 |
| | 8.9 | % | | 27,292 |
| | (3,692 | ) | | (13.5 | )% | 30,764 |
| | 25,696 |
| | 5,068 |
| | 19.7 | % | | 23,600 |
| | 2,096 |
| | 8.9 | % |
New York | 25,064 |
| | 18,687 |
| | 6,377 |
| | 34.1 | % | | 18,772 |
| | (85 | ) | | (0.5 | )% | 26,643 |
| | 25,064 |
| | 1,579 |
| | 6.3 | % | | 18,687 |
| | 6,377 |
| | 34.1 | % |
ERCOT | 19,418 |
| | 17,422 |
| | 1,996 |
| | 11.5 | % | | 15,833 |
| | 1,589 |
| | 10.0 | % | 17,730 |
| | 19,418 |
| | (1,688 | ) | | (8.7 | )% | | 17,422 |
| | 1,996 |
| | 11.5 | % |
Other Power Regions | 21,399 |
| | 21,768 |
| | (369 | ) | | (1.7 | )% | | 26,621 |
| | (4,853 | ) | | (18.2 | )% | 27,490 |
| | 21,399 |
| | 6,091 |
| | 28.5 | % | | 21,768 |
| | (369 | ) | | (1.7 | )% |
Total Supply/Sales by Region | 264,832 |
|
| 262,940 |
|
| 1,892 |
| | 0.7 | % | | 260,029 |
|
| 2,911 |
| | 1.1 | % | 273,554 |
|
| 264,832 |
|
| 8,722 |
| | 3.3 | % | | 262,940 |
|
| 1,892 |
| | 0.7 | % |
__________
| |
(a) | Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants that are fully consolidated (e.g. CENG). |
| |
(b) | Includes affiliate sales to PECO and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016. |
| |
(c) | Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Mid-Atlantic
Year EndedFor the years ended December 31, 2018 compared to 2017 and December 31, 2017 Comparedcompared to Year Ended December 31, 2016,. The $103 million decrease changes in revenues net of purchased power and fuel expense in the Mid-Atlantic primarily reflects lower load volumes, lower realized energy prices and decreased capacity prices, partially offsetRNF by the absence of oil inventory write-downs in 2017 and decreased nuclear outage days.region were as follows:
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $254 million decrease in revenues net of purchased power and fuel expense in the Mid-Atlantic was primarily due to lower realized energy prices, decreased capacity prices and higher oil inventory write-downs in 2016, partially offset by increased load volumes served.Midwest
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The $151 million decrease in revenues net of purchased power and fuel expense in the Midwest primarily reflects lower realized energy prices and increased nuclear outage days, partially offset by decreased fuel prices.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $79 million increase in revenues net of purchased power and fuel expense in the Midwest was primarily due to decreased nuclear outage days and decreased nuclear fuel prices.
New England
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The $76 million increase in revenues net of purchased power and fuel expense in New England was driven by increased capacity prices, partially offset by lower realized energy prices.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $23 million decrease in revenues net of purchased power and fuel expense in New England was primarily due to lower realized energy prices and higher oil inventory write-downs in 2016, partially offset by increased capacity prices.
New York
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $234 million increase in revenues net of purchased power and fuel expense in New York was primarily due to the impact of the New York CES and the acquisition of Fitzpatrick, partially offset by the conclusion of the Ginna Reliability Support Service Agreement and lower realized energy prices.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $108 million increase in revenues net of purchased power and fuel expense in New York was primarily due to the impact of the Ginna Reliability Support Service Agreement, partially offset by lower realized energy prices.
ERCOT
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $51 million increase in revenues net of purchased power and fuel expense in ERCOT was primarily due to the addition of two combined-cycle gas turbines in Texas, partially offset by lower realized energy prices.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $12 million decrease in revenues 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. |
| | | | | | | | |
| 2018 vs. 2017 | 2017 vs. 2016 |
| Increase/(Decrease) | Description | Increase/(Decrease) | Description |
Mid-Atlantic | $ | (141 | ) | • lower realized energy prices, partially offset by • increased capacity prices | $ | (103 | ) | • lower load volumes • lower realized energy prices • decreased capacity prices, partially offset by • the absence of oil inventory write-downs in 2017 • decreased nuclear outage days |
Midwest | 315 |
| • the impact of the Illinois ZES • increased capacity prices, partially offset by • lower realized energy prices | (151 | ) | • lower realized energy prices • increased nuclear outage days, partially offset by • decreased fuel prices |
New England | (160 | ) | • lower realized energy prices, partially offset by • increased capacity prices | 76 |
| • increased capacity prices, partially offset by • lower realized energy prices |
New York | 114 |
| • impact of the New York CES • acquisition of Fitzpatrick, partially offset by • the conclusion of the Ginna Reliability Support Service Agreement | 256 |
| • the impact of the New York CES • acquisition of FitzPatrick, partially offset by • conclusion of the Ginna Reliability Support Service Agreement • lower realized energy prices |
ERCOT | (74 | ) | • deconsolidation of EGTP in 2017, partially offset by • the addition of two combined-cycle gas turbines in Texas | 51 |
| • the addition of two combined-cycle gas turbines in Texas, partially offset by • lower realized energy prices |
Other Power Regions | 70 |
| • higher realized energy prices | (31 | ) | • lower realized energy prices |
Proprietary Trading | 24 |
| • congestion activity | 3 |
| • congestion activity |
Mark-to-Market | (144 | ) | • losses on economic hedging activities of $319 million in 2018 compared to losses of $175 million in 2017 | (134 | ) | • losses on economic hedging activities of $175 million in 2017 compared to losses of $41 million in 2016 |
Other | (70 | ) | • decline in revenues related to the energy efficiency business • the sale of Generation's electrical contracting business in 2018 • accelerated nuclear fuel amortization associated with announced early plant retirements, partially offset by • the absence of amortization of energy contracts recorded at fair value associated with prior acquisitions • gain on the settlement of a long-term gas supply agreement | (84 | ) | • the impacts of declining natural gas prices on Generation's natural gas portfolio • decline in revenues related to the distributed generation business, partially offset by • decrease in accelerated nuclear fuel amortization associated with announced early plant retirements |
Total | $ | (66 | ) | | $ | (117 | ) | |
Other Power Regions
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $31 million decrease in revenues net of purchased power and fuel expense in Other Power Regions was primarily due to lower realized energy prices.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $86 million increase in revenues net of purchased power and fuel expense in Other Power Regions was primarily due to higher realized energy prices.
Proprietary Trading
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $3 million increase in revenues net of purchased power and fuel expense in Proprietary trading was primarily due to congestion activity.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.The $14 million increase in revenues net of purchased power and fuel expense in Proprietary trading was primarily due to congestion activity.
Mark-to-market
Generation is exposed to market risks associated with changes in commodity prices and executes economic hedges to mitigate exposure to these fluctuations. See Note 11 — Fair Value of Financial Assets and Liabilities and Note 12 — Derivative Financial Instruments of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. Mark-to-market losses on economic hedging activities were $175 million in 2017 compared to losses of $41 million in 2016.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Mark-to-market losses on economic hedging activities were $41 million in 2016 compared to gains of $257 million in 2015.
Other
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.The $90 million decrease in other revenue net of purchased power and fuel was primarily due to the impacts of declining natural gas prices on Generation's natural gas portfolio and the decline in revenues related to the distributed generation business, partially offset by a decrease in accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Financial Statements.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.The $107 million increase in other revenue net of purchased power and fuel was primarily due to revenue related to the inclusion of Pepco Energy Services results in 2016 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 the initial early retirement decision for Clinton and Quad Cities as discussed in Note 8 — Early Nuclear Plant Retirements of the Combined Notes to the Financial Statements.
Nuclear Fleet Capacity Factor
Factor. The following table presents nuclear fleet operating data for 2017, as compared to 2016 and 2015, for the Generation-operated plants.plants, which reflects ownership percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG Nuclear, LLC and including the ownership of the FitzPatrick nuclear facility from March 31, 2017. 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.
| | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Nuclear fleet capacity factor(a) | 94.1 | % | | 94.6 | % | | 93.7 | % | 94.6 | % | | 94.1 | % | | 94.6 | % |
Refueling outage days(a) | 293 |
| | 245 |
| | 290 |
| 274 |
| | 293 |
| | 245 |
|
Non-refueling outage days(a) | 53 |
| | 63 |
| | 82 |
| 38 |
| | 53 |
| | 63 |
|
The changes in Operating and maintenance expense, consisted of the following:
|
| | | |
| Increase (Decrease) 2018 vs. 2017(a) |
Impairment and related charges of certain generating assets(b) | $ | (432 | ) |
Merger and integration costs(c) | (68 | ) |
Insurance | (36 | ) |
Pension and non-pension postretirement benefits expense | (22 | ) |
BSC costs | 13 |
|
Plant retirements and divestitures(d) | 53 |
|
Accretion expense | (14 | ) |
Nuclear refueling outage costs, including the co-owned Salem plant | (24 | ) |
Labor, other benefits, contracting and materials(e) | (255 | ) |
Vacation policy change(f) | 40 |
|
Change in environmental liabilities | (45 | ) |
Other | (45 | ) |
Decrease in operating and maintenance expense | $ | (835 | ) |
__________
| |
(a) | Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017. |
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The nuclear fleet capacity factor, which excludes Salem, decreased in 2017 compared to 2016 primarily due to increased refueling outage days, partially offset by fewer non-refueling outage days.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The nuclear fleet capacity factor, which excludes Salem, increased in 2016 compared to 2015 primarily due to fewer refueling and non-refueling outage days.
Operating and Maintenance Expense
The changes in operating and maintenance expense for 2017 compared to 2016, consisted of the following:
|
| | | |
(b) | Increase
(Decrease)(a) Primarily reflects the impairment of certain wind projects in 2018 and charges to earnings related to impairments as a result of the EGTP assets in 2017. |
| |
Impairment and related charges of certain generating assets(b) (c) | $ | 307 |
|
MergerPrimarily reflects merger and integration costs associated with the PHI and FitzPatrick acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities. |
| 13 |
|
(d) | Primarily represents the announcement to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO update(c)compared to the previous decision to early retire the TMI nuclear facility in 2017. |
| 84 |
|
Pension(e) | Primarily reflects decreased spending related to energy efficiency projects and non-pension postretirement benefits expensedecreased costs related to the sale of Generation's electrical contracting business. |
| 10 |
|
Corporate allocations(f) | 23 |
|
Plant retirements and divestitures(d)
| 127 |
|
Accretion expense(e)
| 35 |
|
Nuclear refueling outage costs, includingPrimarily reflects the co-owned Salem plant(f)
| 104 |
|
Merger commitments(g)
| (53 | ) |
Labor, other benefits, contracting and materials(h)
| 52 |
|
Cost management program | (2 | ) |
Curtailmentreversal of Generation growth and development activities(j)
| (24 | ) |
Vacation policypreviously accrued vacation expenses as a result of a change(i)
| (40 | ) |
Allowance for uncollectible accounts | 33 |
|
Change in Environmental Remediation Liabilities | 44 |
|
Other | (63 | ) |
Increase in operating and maintenance expense | $ | 650 | Exelon's vacation vesting policy. |
|
| | | |
| Increase (Decrease) 2017 vs. 2016(a) |
Impairment and related charges of certain generating assets (b) | $ | 307 |
|
Merger and integration costs | 13 |
|
ARO update(c) | 84 |
|
Pension and non-pension postretirement benefits expense(c) | 10 |
|
BSC costs | 23 |
|
Plant retirements and divestitures(d) | 127 |
|
Accretion expense(e) | 35 |
|
Nuclear refueling outage costs, including the co-owned Salem plant(f) | 104 |
|
Merger commitments(g) | (53 | ) |
Labor, other benefits, contracting and materials(h) | 38 |
|
Cost management program | (2 | ) |
Curtailment of Generation growth and development activities(i) | (24 | ) |
Vacation policy change(j) | (40 | ) |
Allowance for uncollectible accounts | 33 |
|
Change in environmental liabilities | 44 |
|
Other | (63 | ) |
Increase in operating and maintenance expense | $ | 636 |
|
__________
| |
(a) | The 2017 financial results include Generation's acquisitionIncludes the ownership of the FitzPatrick nuclear generating stationfacility from March 31, 2017. |
| |
(b) | Primarily reflects charges to earnings related to impairments as a result of the EGTP assets in 2017 and impairment of Upstream assets and certain wind projects in 2016. |
| |
(c) | Primarily reflects the non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to 2016. |
| |
(d) | Primarily represents the announcement of the early retirement of Generation'sthe TMI nuclear facility in 2017 compared to the previous decision to early retire Generation'sthe Clinton and Quad Cities nuclear facilities in 2016. |
| |
(e) | Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017. |
| |
(f) | Primarily reflects an increase in the number of nuclear outage days during 2017 compared to 2016. |
| |
(g) | Primarily represents costs incurred as part of the settlement orders approving the PHI acquisitionmerger during 2016. |
| |
(h) | Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017. |
| |
(i) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
| |
(j) | Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
The changes in operating and maintenance expense for 2016 compared to 2015, consisted of the following:
|
| | | |
| Increase (Decrease) |
Impairment and related charges of certain generating assets (a) | $ | 161 |
|
Merger and integration costs | 27 |
|
Midwest Generation bankruptcy charges | 10 |
|
ARO update(b) | (79 | ) |
Pension and non-pension postretirement benefits expense(c) | (42 | ) |
Corporate allocations(d) | (12 | ) |
Plant retirements and divestitures(e) | (50 | ) |
Accretion expense | (21 | ) |
Nuclear refueling outage costs, including the co-owned Salem plant(f) | (61 | ) |
Merger commitments | 53 |
|
Labor, other benefits, contracting and materials(g) | 185 |
|
Cost management program(h) | 43 |
|
Curtailment of Generation growth and development activities(i) | 24 |
|
Other | 95 |
|
Increase in operating and maintenance expense | $ | 333 |
|
__________
| |
(a) | Reflects increased impairments in 2016 compared to 2015, primarily related to the impairments of certain Upstream assets and wind generating assets in 2016. |
| |
(b) | Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units. |
| |
(c) | Reflects the favorable impact of higher pension and OPEB discount rates. |
| |
(d) | Reflects a decreased share of corporate allocated costs. |
| |
(e) | Reflects the impact of the Generation's previous decision to early retire the Clinton and Quad Cities nuclear facilities. |
| |
(f) | Reflects the favorable impacts of decreased nuclear outages in 2016. |
| |
(g) | Reflects an increase of labor, other benefits, contracting and materials costs primarily due to increased contracting costs related to energy efficiency projects and the inclusion of Pepco Energy Services results in 2016. Also includes cost of sales of our other business activities that are not allocated to a region. |
| |
(h) | Represents the 2016 severance expense and reorganization costs related to a cost management program. |
| |
(i) | Reflects the one-time recognition for asset impairment charges pursuant to Generation's strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities. |
| |
(j) | Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy. |
Depreciation and Amortization
amortization expense Year Endedfor the year ended December 31, 2018 compared to the year ended December 31, 2017 Comparedincreased primarily due to Year Ended December 31, 2016accelerated depreciation and amortization expenses associated with the decision to early retire the Oyster Creek nuclear facility in 2018 compared to the previous decision to early retire the TMI nuclear facility in 2017.
.Depreciation and amortization expense for the year ended December 31, 2017 compared to the year ended December 31, 2016 decreased primarily due to accelerated depreciation and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016 compared to the decision to early retire the Three Mile IslandTMI nuclear facility in 2017.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Depreciation and amortization expense increased primarily due to accelerated depreciation and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear facilities in 2016, and increased depreciation expense due to ongoing capital expenditures.
Taxes Other Than Income
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The increase in taxes other than income was primarily due to increased real estate taxes and sales and use taxes.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The increase in taxes other than income was primarily due to an increase in gross receipts tax.
Gain (Loss) on Sales of Assets
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The increase in gain (loss) on sales of assets isand businesses for the year ended December 31, 2018 compared to the year ended December 31, 2017 increased due to Generation's 2018 sale of its electrical contracting business.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2017 compared to the year ended December 31, 2016 increased primarily due to certain Generation projects and contracts being terminated or renegotiated in 2016, partially offset by a gain associated with Generation’s sale of the retired New Boston generating site in 2016.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The decrease in gain (loss) on sales of assets is primarily related to the one-time recognition for a loss on sale of assets pursuant to Generation's strategic decision in the fourth quarter of 2016 to narrow the scope and scale of its growth and development activities, partially offset by a gain associated with Generation's sale of the retired New Boston generating site in 2016.
Bargain Purchase Gain
Year EndedBargain purchase gain for the year ended December 31, 2017 Compared2018 compared to Year Endedthe year ended December 31, 2016. The increase in the Bargain purchase gain is related to the2017. decreased as a result of the gain associated with the FitzPatrick acquisition. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
Gain on Deconsolidation of Business
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The increase in the Gain on deconsolidation of business is relatedfor the year ended December 31, 2018 compared to the year ended December 31, 2017 decreased due to the deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information.
Interest Expense
The changes in interest expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Interest expense on long-term debt | $ | — |
| | $ | 8 |
|
Interest expense on interest rate swaps | (2 | ) | | 1 |
|
Interest expense on tax settlements | 12 |
| | 16 |
|
Other interest expense | 66 |
| | (26 | ) |
(Decrease) increase in interest expense, net | $ | 76 |
| | $ | (1 | ) |
Other, Net
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. The increase in Other, netdecreased primarily reflectsdue to the net increasedecrease in realized and unrealized gains related to the NDT fund investmentsfunds of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $45 million, $209 million and $80 million for the years ended December 31, 2018, 2017 and 2016 respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT fund investmentsfunds of the Regulatory Agreement Units. Refer toSee Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fund investments.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The increase in Other, net primarily reflects the net increase in realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the table below. Other, net also reflects $80 million and $(22) million for the years ended December 31, 2016 and 2015, respectively, related to the contractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement Units. Refer to Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fund investments.funds.
The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units recognized in Other, net for 2017, 2016 and 2015:Units:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
Net unrealized gains (losses) on decommissioning trust funds | $ | 521 |
| | $ | 194 |
| | $ | (197 | ) |
Net realized gains on sale of decommissioning trust funds | 95 |
| | 35 |
| | 66 |
|
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Net unrealized (losses) gains on NDT funds | $ | (483 | ) | | $ | 521 |
| | $ | 194 |
|
Net realized gains on sale of NDT funds | 180 |
| | 95 |
| | 35 |
|
Effective Income Tax Rate
Generation’s effective income tax rates were (29.5)%, (94.6)% and 32.9% for the years ended December 31, 2018, 2017 and 2016, and 2015 were (96.2)%, 33.2% and 27.1%, respectively. The increase is primarily related to impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussionadditional information of the change in the effective income tax rate.
Results of Operations—ComEd
| | | 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 5,536 |
| | $ | 5,254 |
| | $ | 282 |
| | $ | 4,905 |
| | $ | 349 |
| $ | 5,882 |
| | $ | 5,536 |
| | $ | 346 |
| | $ | 5,254 |
| | $ | 282 |
|
Purchased power expense | 1,641 |
| | 1,458 |
| | (183 | ) | | 1,319 |
| | (139 | ) | 2,155 |
| | 1,641 |
| | (514 | ) | | 1,458 |
| | (183 | ) |
Revenues net of purchased power expense(b) | 3,895 |
| | 3,796 |
| | 99 |
| | 3,586 |
| | 210 |
| 3,727 |
| | 3,895 |
| | (168 | ) | | 3,796 |
| | 99 |
|
Other operating expenses | | | | | | | | | | | | | | | | | | |
Operating and maintenance | 1,427 |
| | 1,530 |
| | 103 |
| | 1,567 |
| | 37 |
| 1,335 |
| | 1,427 |
| | 92 |
| | 1,530 |
| | 103 |
|
Depreciation and amortization | 850 |
| | 775 |
| | (75 | ) | | 707 |
| | (68 | ) | 940 |
| | 850 |
| | (90 | ) | | 775 |
| | (75 | ) |
Taxes other than income | 296 |
| | 293 |
| | (3 | ) | | 296 |
| | 3 |
| 311 |
| | 296 |
| | (15 | ) | | 293 |
| | (3 | ) |
Total other operating expenses | 2,573 |
| | 2,598 |
| | 25 |
| | 2,570 |
| | (28 | ) | 2,586 |
| | 2,573 |
| | (13 | ) | | 2,598 |
| | 25 |
|
Gain on sales of assets | 1 |
| | 7 |
| | (6 | ) | | 1 |
| | 6 |
| 5 |
| | 1 |
| | 4 |
| | 7 |
| | (6 | ) |
Operating income | 1,323 |
| | 1,205 |
| | 118 |
| | 1,017 |
| | 188 |
| 1,146 |
| | 1,323 |
| | (177 | ) | | 1,205 |
| | 118 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | | |
Interest expense, net | (361 | ) | | (461 | ) | | 100 |
| | (332 | ) | | (129 | ) | (347 | ) | | (361 | ) | | 14 |
| | (461 | ) | | 100 |
|
Other, net | 22 |
| | (65 | ) | | 87 |
| | 21 |
| | (86 | ) | 33 |
| | 22 |
| | 11 |
| | (65 | ) | | 87 |
|
Total other income and (deductions) | (339 | ) | | (526 | ) | | 187 |
| | (311 | ) | | (215 | ) | (314 | ) | | (339 | ) | | 25 |
| | (526 | ) | | 187 |
|
Income before income taxes | 984 |
| | 679 |
| | 305 |
| | 706 |
| | (27 | ) | 832 |
| | 984 |
| | (152 | ) | | 679 |
| | 305 |
|
Income taxes | 417 |
| | 301 |
| | (116 | ) | | 280 |
| | (21 | ) | 168 |
| | 417 |
| | 249 |
| | 301 |
| | (116 | ) |
Net income | $ | 567 |
| | $ | 378 |
| | $ | 189 |
| | $ | 426 |
| | $ | (48 | ) | $ | 664 |
| | $ | 567 |
| | $ | 97 |
| | $ | 378 |
| | $ | 189 |
|
__________
| |
(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). |
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017.Net Incomeincome increased by $97 million primarily due to higher electric distribution and energy efficiency formula rate earnings (reflecting the impacts of increased capital investment). The TCJA did not significantly impact Net income as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. ComEd’s Net income for the year ended December 31, 2017 was higher than the same period in 2016 increased $189 million 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 in 2016 and increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric distribution ROE). The higher Net income was partially offset by the impact of weather conditions in 2016. See Revenue Decoupling discussion below for additional information on the impact of weather.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.ComEd’s Net income for the year ended December 31, 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.
Revenues Net of Purchased Power Expense
Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd is permitted to recoverrecovers electricity, REC and ZEC procurement costs from retail customers without mark-up. Therefore, fluctuations in these costs have no impact on Revenue net of purchased power expense. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement process.RNF.
All ComEd customersCustomers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact ComEd’sthe volume of deliveries, but do affect ComEd’simpact Operating revenues related to supplied energy, which is fully offsetelectricity.
The changes 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 years ended December 31, 2017, 2016 and 2015,RNF consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Electric | 70 | % | | 72 | % | | 76 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2017, 2016 and 2015 consisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 1,371,700 |
| | 34 | % | | 1,502,900 |
| | 38 | % | | 1,655,400 |
| | 42 | % |
The changes in ComEd’s Revenue net of purchased power expense for the year ended December 31, 2017, compared to the same period in 2016, and for the year ended December 31, 2016, compared to the same period in 2015, consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Weather(a) | $ | (36 | ) | | $ | 54 |
| $ | — |
| | $ | (36 | ) |
Volume(a) | (5 | ) | | (2 | ) | — |
| | (5 | ) |
Pricing and customer mix(a) | (18 | ) | | 14 |
| — |
| | (18 | ) |
Electric distribution revenue | 170 |
| | 69 |
| (127 | ) | | 170 |
|
Transmission revenue | 60 |
| | 97 |
| (43 | ) | | 60 |
|
Energy efficiency revenue(b) | 16 |
| | — |
| 47 |
| | 16 |
|
Regulatory required programs(b) | (85 | ) | | (31 | ) | (97 | ) | | (85 | ) |
Uncollectible accounts recovery, net | (7 | ) | | (13 | ) | 6 |
| | (7 | ) |
Other | 4 |
| | 22 |
| 46 |
| | 4 |
|
Total increase | $ | 99 |
| | $ | 210 |
| |
Total (decrease) increase | | $ | (168 | ) | | $ | 99 |
|
__________
| |
(a) | For the year ended December 31, 2017, compared to the same period in 2016, the changes reflect the 2016 impacts of weather, volume and pricing and customer mix. As further described below, pursuantPursuant 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. |
| |
(b) | Beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures. |
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, mildHowever, beginning January 1, 2017, Operating revenues are not impacted by abnormal weather, reduces demand.
Under EIMA, ComEd'susage per customer or number of customers as a result of a change to the electric distribution formula rate provided for an adjustmentpursuant to future billings if its earned ROE fell outside a 50-basis-point collar of its allowed ROE, which partially eliminated the impacts of weather and 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, numbers of customers or usage per customer. ComEd began recognizing the impacts of this change beginning in the first quarter of 2017. For the year ended December 31, 2017, ComEd recorded an increase to Electric distribution revenues of approximately $32 million to eliminate weather and load impacts.
For the year ended December 31, 2016, favorable weather conditions increased Operating revenues net of purchased power expense when compared to the prior year.
For the year ended December 31, 2016, the increase in Revenue net of purchased power as a result of pricing and customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in customer mix.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in 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 years ended December 31, 2017, 2016 and 2015 consisted of the following:
|
| | | | | | | | | | | | | | |
Heating and Cooling Degree-Days | For the Years Ended December 31, | | | | % Change |
2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 5,435 |
| | 5,715 |
| | 6,198 |
| | (4.9 | )% | | (12.3 | )% |
Cooling Degree-Days | 991 |
| | 1,157 |
| | 893 |
| | (14.3 | )% | | 11.0 | % |
|
| | | | | | | | | | | | | | |
Heating and Cooling Degree-Days | For the Years Ended December 31, | | | | % Change |
2016 | | 2015 | | Normal | | 2016 vs. 2015 | | 2016 vs. Normal |
Heating Degree-Days | 5,715 |
| | 6,091 |
| | 6,198 |
| | (6.2 | )% | | (7.8 | )% |
Cooling Degree-Days | 1,157 |
| | 806 |
| | 893 |
| | 43.5 | % | | 29.6 | % |
FEJA.Electric Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and allowed ROE. ComEd's allowed ROE isDuring the annual average rate on 30-year treasury notes plus 580 basis points. In addition, ComEd's allowed ROE is subjectyear ended December 31, 2018, as compared to reduction if ComEd does not deliver the reliability and customer service benefitssame period in 2017, electric distribution revenue decreased $127 million, primarily due to which it has committed over the ten-year lifeimpact of the investment program.lower federal income tax rate, partially offset by increased revenues due to higher rate base and increased Depreciation expense. During the year ended December 31, 2017, as compared to the same period in 2016, electric distribution revenue increased $170 million, primarily due to increased capital investment, increased Depreciation expense, higher allowed ROE due to an increase in treasury rates and revenue decoupling impacts (as described above). During the year ended December 31, 2016, electric distribution revenue increased $69 million, primarily due to increased capital investment and Depreciation expense, partially offset by lower allowed ROE due to a decrease in treasury rates. See Operating and Maintenance Expense below and Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. ForTransmission revenue decreased for the yearsyear ended December 31, 2018, primarily due to decreased peak load and the impact of the lower federal tax rate, partially offset by increased revenues due to higher rate base and increased Depreciation expense. Transmission revenue increased for the year ended December 31, 2017, and 2016, ComEd recorded increased transmission revenueprimarily due to increased capital investment, higher Depreciation expense, and increased highest daily peak load. See Operating and Maintenance Expense below and Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue.Beginning June 1, 2017, FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency 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 on 30-year treasury notes plus 580 basis points. Beginning January 1, 2018, ComEd’s allowed ROE 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. See Depreciation and amortization expense discussions below and Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs.Programs This represents the change in Operatingrepresent revenues collected under approved rate riders to recover costs incurred for regulatory programs such as ComEd's purchased power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and current cost recovery. An equal and offsetting amount has beenThe costs of such programs are included in Operating and maintenance expense. See OperatingRevenues from regulatory programs decreased for the year ended December 31, 2018, as compared to the same period in 2017, and maintenance expense discussion below for additional informationthe year ended December 31, 2017, as compared to the same period in 2016, primarily due to the fact that beginning on included programs.June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
Uncollectible Accounts Recovery, Net.NetUncollectible accounts recovery, net, represents recoveries under ComEd’sthe uncollectible accounts tariff. See Operating and maintenance expense discussion below for additional information on this tariff.
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,revenues and recoveries of environmental costs associated with MGP sites,sites. The increase in Other revenue for the years ended December 31, 2018, as compared to the same period in 2017 primarily reflects mutual assistance revenues associated with hurricane and recoveries of energy procurement costs.
winter storm restoration efforts. An equal and offsetting amount has been included in Operating and Maintenance Expensemaintenance expense and Taxes other than income.
See Note 24 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | 2017 vs. 2016 | | 2016 | | 2015 | | 2016 vs. 2015 |
Operating and maintenance expense—baseline | $ | 1,329 |
| | $ | 1,347 |
| | $ | (18 | ) | | $ | 1,347 |
| | $ | 1,353 |
| | $ | (6 | ) |
Operating and maintenance expense—regulatory required programs(a) | 98 |
| | 183 |
| | (85 | ) | | 183 |
| | 214 |
| | (31 | ) |
Total operating and maintenance expense | $ | 1,427 |
| | $ | 1,530 |
| | $ | (103 | ) | | $ | 1,530 |
| | $ | 1,567 |
| | $ | (37 | ) |
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | |
Labor, other benefits, contracting and materials(a) | $ | 20 |
| | $ | (41 | ) |
Pension and non-pension postretirement benefits expense | — |
| | 3 |
|
Storm costs | (19 | ) | | 2 |
|
Uncollectible accounts expense—provision(b) | 5 |
| | (6 | ) |
Uncollectible accounts expense—recovery, net(b) | 1 |
| | (1 | ) |
BSC costs(a)(c) | (5 | ) | | 44 |
|
Other(a) | 3 |
| | (19 | ) |
| 5 |
| | (18 | ) |
Regulatory required programs | | | |
Energy efficiency and demand response programs(d) | (97 | ) | | (85 | ) |
Decrease in operating and maintenance expense | $ | (92 | ) | | $ | (103 | ) |
__________
| |
(a) | Operating and maintenance expense for regulatory required programs areIncludes costs for various legislative and/or regulatory programs that are recoverable from customers on a full and current basis through approved regulated rates.associated with mutual assistance provided to other utilities in 2018. An equal and offsetting amountincrease has been reflectedrecognized in Operating revenues. |
The changes in Operating and maintenance expense for year ended December 31, 2017, compared to the same period in 2016, and for the year ended December 31, 2016, compared to the same period in 2015, consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | (41 | ) | | $ | 12 |
|
Pension and non-pension postretirement benefits expense(a) | 3 |
| | (24 | ) |
Storm-related costs | 2 |
| | (9 | ) |
Uncollectible accounts expense—provision(b) | (6 | ) | | 5 |
|
Uncollectible accounts expense—recovery, net(b) | (1 | ) | | (18 | ) |
BSC costs(c) | 44 |
| | 29 |
|
Other | (19 | ) | | (1 | ) |
| (18 | ) | | (6 | ) |
Regulatory required programs | | | |
Energy efficiency and demand response programs(d) | (85 | ) | | (31 | ) |
Decrease in operating and maintenance expense | $ | (103 | ) | | $ | (37 | ) |
__________
| |
(a) | Primarily reflects the favorable impact of higher assumed pension and OPEB discount ratesrevenues for the year ended December 31, 2016.period presented. |
| |
(b) | ComEd is allowed to recover from or refund to customers the difference between the utility’sits annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. ComEd recorded a net decrease in 2017 and 2016 in Operating and maintenance expense related to uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
| |
(c) | PrimarilyFor the year ended December 31, 2017, primarily reflects increased information technology support services from BSC in 2017 and 2016. For the year ended December 31, 2017, includes the $8 million write-off of a regulatory asset related to Constellation merger and integration costs for which recovery is no longer expected. |
| |
(d) | Beginning on June 1, 2017 ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency over the weighted average useful life of the related energy efficiency measures. |
Depreciation and Amortization Expense
The increases in Depreciation and amortization expense for 2017 compared to 2016, and 2016 compared to 2015, consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase 2018 vs. 2017 | | Increase 2017 vs. 2016 |
Depreciation expense(a) | $ | 60 |
| | $ | 58 |
| $ | 36 |
| | $ | 60 |
|
Regulatory asset amortization(b) | 7 |
| | (5 | ) | 53 |
| | 7 |
|
Other | 8 |
| | 15 |
| 1 |
| | 8 |
|
Total increase | $ | 75 |
| | $ | 68 |
| $ | 90 |
| | $ | 75 |
|
__________
| |
(a) | Primarily reflects ongoing capital expenditures for the years ended December 31, 2017 and 2016.expenditures. |
| |
(b) | Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset. |
Taxes Other Than Income
Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes other than income taxes remained relatively consistentThe decrease in Interest expense, net, for the year ended December 31, 2017,2018 compared to the same period in 2016,2017, and for the year ended December 31, 2016, compared to the same period in 2015.
Gain on Sale of Assets
Gain on sale of assets decreased during the year ended December 31, 2017, compared to the same period in 2016, and increased during the year ended December 31, 2016, compared to the same period in 2015, primarily due to the sale of land during March 2016.
Interest Expense, Net
The increase (decrease) in Interest expense, net, for the year ended 2017 compared to the same period in 2016, and for the year ended 2016, compared to the same period in 2015, consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Interest expense related to uncertain tax positions(a) | $ | (104 | ) | | $ | 109 |
| $ | (13 | ) | | $ | (104 | ) |
Interest expense on debt (including financing trusts)(b) | 6 |
| | 24 |
| 2 |
| | 6 |
|
Other | (2 | ) | | (4 | ) | (3 | ) | | (2 | ) |
Increase (decrease) in interest expense, net | $ | (100 | ) | | $ | 129 |
| |
Decrease in interest expense, net | | $ | (14 | ) | | $ | (100 | ) |
__________
| |
(a) | Primarily reflects the recognition of after-tax interest related to the Tax Court's decision on Exelon's like-kind exchange tax position in the 2016. For the year ended December 31, 2017, the decrease was partially offset by additional interest recorded in 2017 related to Exelon's like-kind exchange tax position.2016 and 2017. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(b) | Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds for the years ended December 31, 2016. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd's debt obligations. |
Other, Net
The increase (decrease) in Other, net, for the year ended 2018 compared to the same period in 2017, and for the year ended 2017 compared to the same period in 2016, and for the year ended 2016 compared to the same period in 2015, consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Other income and deductions, net(a) | $ | 88 |
| | $ | (94 | ) | $ | 1 |
| | $ | 88 |
|
AFUDC equity | (2 | ) | | 9 |
| 7 |
| | (2 | ) |
Other | 1 |
| | (1 | ) | 3 |
| | 1 |
|
Increase (decrease) in Other, net | $ | 87 |
| | $ | (86 | ) | $ | 11 |
| | $ | 87 |
|
__________
| |
(a) | Primarily reflects the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. |
Effective Income Tax Rate
ComEd’s effective income tax rates for the years ended December 31, 2018, 2017 and 2016, were 20.2%, 42.4% and 2015, were 42.4%, 44.3% and 39.7%, respectively. The decrease in the effective income tax rate for the year ended December 31, 2018, compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. The decrease in the effective income tax rate for the year ended December 31, 2017, compared to the same period in 2016 is primarily due to the recognition of a non-deductible penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
ComEd Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather- Normal % Change |
Retail Deliveries (a) | | | | | | | | | | | | | |
Residential | 26,292 |
| | 27,790 |
| | (5.4 | )% | | (0.9 | )% | | 26,496 |
| | 4.9 | % | | (0.6 | )% |
Small commercial & industrial | 31,332 |
| | 31,975 |
| | (2.0 | )% | | (0.7 | )% | | 31,717 |
| | 0.8 | % | | (0.3 | )% |
Large commercial & industrial | 27,467 |
| | 27,842 |
| | (1.3 | )% | | (0.5 | )% | | 27,210 |
| | 2.3 | % | | 1.5 | % |
Public authorities & electric railroads | 1,286 |
| | 1,298 |
| | (0.9 | )% | | (0.3 | )% | | 1,309 |
| | (0.8 | )% | | (0.8 | )% |
Total retail deliveries | 86,377 |
| | 88,905 |
| | (2.8 | )% | | (0.7 | )% | | 86,732 |
| | 2.5 | % | | 0.2 | % |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 3,624,372 |
| | 3,595,376 |
| | 3,550,239 |
|
Small commercial & industrial | 378,345 |
| | 374,644 |
| | 370,932 |
|
Large commercial & industrial | 1,959 |
| | 2,007 |
| | 1,976 |
|
Public authorities & electric railroads | 4,775 |
| | 4,750 |
| | 4,820 |
|
Total | 4,009,451 |
| | 3,976,777 |
| | 3,927,967 |
|
|
| | | | | | | | | | | | | | | | | |
Electric Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Residential | $ | 2,746 |
| | $ | 2,597 |
| | 5.7 | % | | $ | 2,360 |
| | 10.0 | % |
Small commercial & industrial | 1,376 |
| | 1,316 |
| | 4.6 | % | | 1,337 |
| | (1.6 | )% |
Large commercial & industrial | 461 |
| | 462 |
| | (0.2 | )% | | 443 |
| | 4.3 | % |
Public authorities & electric railroads | 44 |
| | 45 |
| | (2.2 | )% | | 42 |
| | 7.1 | % |
Total retail | 4,627 |
| | 4,420 |
| | 4.7 | % | | 4,182 |
| | 5.7 | % |
Other revenue(b) | 909 |
| | 834 |
| | 9.0 | % | | 723 |
| | 15.4 | % |
Total electric revenue(c) | $ | 5,536 |
| | $ | 5,254 |
| | 5.4 | % | | $ | 4,905 |
| | 7.1 | % |
__________
| |
(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 $15 million, $15 million, and $4 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
Results of Operations—PECO
| | | 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 2,870 |
| | $ | 2,994 |
| | $ | (124 | ) | | $ | 3,032 |
| | $ | (38 | ) | $ | 3,038 |
| | $ | 2,870 |
| | $ | 168 |
| | $ | 2,994 |
| | $ | (124 | ) |
Purchased power and fuel expense | 969 |
| | 1,047 |
| | 78 |
| | 1,190 |
| | 143 |
| 1,090 |
| | 969 |
| | (121 | ) | | 1,047 |
| | 78 |
|
Revenues net of purchased power and fuel expense (a) | 1,901 |
| | 1,947 |
| | (46 | ) | | 1,842 |
| | 105 |
| 1,948 |
| | 1,901 |
| | 47 |
| | 1,947 |
| | (46 | ) |
Other operating expenses | | | | | | | | | | | | | | | | | | |
Operating and maintenance | 806 |
| | 811 |
| | 5 |
| | 794 |
| | (17 | ) | 898 |
| | 806 |
| | (92 | ) | | 811 |
| | 5 |
|
Depreciation and amortization | 286 |
| | 270 |
| | (16 | ) | | 260 |
| | (10 | ) | 301 |
| | 286 |
| | (15 | ) | | 270 |
| | (16 | ) |
Taxes other than income | 154 |
| | 164 |
| | 10 |
| | 160 |
| | (4 | ) | 163 |
| | 154 |
| | (9 | ) | | 164 |
| | 10 |
|
Total other operating expenses | 1,246 |
| | 1,245 |
| | (1 | ) | | 1,214 |
| | (31 | ) | 1,362 |
| | 1,246 |
| | (116 | ) | | 1,245 |
| | (1 | ) |
Gain on sales of assets | — |
| | — |
| | — |
| | 2 |
| | (2 | ) | 1 |
| | — |
| | 1 |
| | — |
| | — |
|
Operating income | 655 |
| | 702 |
| | (47 | ) | | 630 |
| | 72 |
| 587 |
| | 655 |
| | (68 | ) | | 702 |
| | (47 | ) |
Other income and (deductions) | | | | | | | | | | | | | | | | | | |
Interest expense, net | (126 | ) | | (123 | ) | | (3 | ) | | (114 | ) | | (9 | ) | (129 | ) | | (126 | ) | | (3 | ) | | (123 | ) | | (3 | ) |
Other, net | 9 |
| | 8 |
| | 1 |
| | 5 |
| | 3 |
| 8 |
| | 9 |
| | (1 | ) | | 8 |
| | 1 |
|
Total other income and (deductions) | (117 | ) | | (115 | ) | | (2 | ) | | (109 | ) | | (6 | ) | (121 | ) | | (117 | ) | | (4 | ) | | (115 | ) | | (2 | ) |
Income before income taxes | 538 |
| | 587 |
| | (49 | ) | | 521 |
| | 66 |
| 466 |
| | 538 |
| | (72 | ) | | 587 |
| | (49 | ) |
Income taxes | 104 |
| | 149 |
| | 45 |
| | 143 |
| | (6 | ) | 6 |
| | 104 |
| | 98 |
| | 149 |
| | 45 |
|
Net income | $ | 434 |
| | $ | 438 |
| | $ | (4 | ) | | $ | 378 |
| | $ | 60 |
| $ | 460 |
| | $ | 434 |
| | $ | 26 |
| | $ | 438 |
| | $ | (4 | ) |
__________
| |
(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 a presentation defined under GAAP and may not be comparable to other companies’ presentations or more useful than the GAAP information provided elsewhere in this report. |
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017.Net income was higher due to favorable weather and volumes. The TCJA did not significantly impact Net Income as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass back the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016. PECO's netNet income for the year ended December 31, 2017 was lower than the same period in 2016, primarily due to a decrease in Revenues net of purchased power and fuel expenseunfavorable weather. The TCJA did not significantly impact Net Income as a result of unfavorable weather in PECO's service territory, partiallythe favorable income tax impacts were predominantly offset by lower revenues resulting from the one-time non-cash impacts associated withrequirement to pass back the Tax Cuts and Jobs Act in 2017.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. PECO's net income for the year ended December 31, 2016 was higher than the same period in 2015, primarily due to an increase in Revenues 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.tax savings through customer rates.
Revenues Net of Purchased Power and Fuel ExpenseExpense.
Electric and natural gas revenue and purchasedThere are certain drivers of Operating revenues that are fully offset by their impact on Purchased power and fuel expense are affected by fluctuationsexpenses such as commodity and REC procurement costs and participation in commodity procurement costs.customer choice programs. PECO's electric supply and natural gas cost rates charged to customers
are subject to adjustments as specified in the PAPUC-approved tariffs that are designed to recover or refund the difference between the actual cost of electric supply andrecovers electricity, natural gas and the amount included in rates in accordance with PECO's GSA and PGC, respectively.REC procurement costs from customers without mark-up. Therefore, fluctuations in electric supply and natural gas procurementthese costs have no impact on electric and natural gas revenues net of purchased power and fuel expense.RNF.
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 customersCustomers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers, respectively. The customer’ssuppliers. Customer choice of suppliers doesprograms do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energyelectricity and natural gas service. Customer Choice Program activity has no impact on electric and natural gas revenue net of purchase power and fuel expense.gas.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the years ended December 31, 2017, 2016, and 2015 consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Electric | 71 | % | | 70 | % | | 70 | % |
Natural Gas | 26 | % | | 26 | % | | 25 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at December 31, 2017, 2016, and 2015The changes in RNFconsisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 565,900 |
| | 35 | % | | 587,200 |
| | 36 | % | | 563,400 |
| | 35 | % |
Natural Gas | 83,800 |
| | 16 | % | | 81,300 |
| | 16 | % | | 81,100 |
| | 16 | % |
The changes in PECO’s Operating revenues net of purchased power and fuel expense for the years ended December 31, 2017 and December 31, 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:
| | | 2017 vs. 2016 | | 2016 vs. 2015 | 2018 vs. 2017 | | 2017 vs. 2016 |
| Increase (Decrease) | | Increase (Decrease) | Increase (Decrease) | | Increase (Decrease) |
| Electric | | Gas | | Total | | Electric | | Gas | | Total | Electric | | Gas | | Total | | Electric | | Gas | | Total |
Weather | $ | (28 | ) | | $ | 4 |
| | $ | (24 | ) | | $ | 1 |
| | $ | (12 | ) | | $ | (11 | ) | $ | 39 |
| | $ | 22 |
| | $ | 61 |
| | $ | (28 | ) | | $ | 4 |
| | $ | (24 | ) |
Volume | (18 | ) | | 3 |
| | (15 | ) | | 6 |
| | 4 |
| | 10 |
| 37 |
| | 4 |
| | 41 |
| | (18 | ) | | 3 |
| | (15 | ) |
Pricing | 8 |
| | 2 |
| | 10 |
| | 160 |
| | (1 | ) | | 159 |
| (75 | ) | | (1 | ) | | (76 | ) | | 8 |
| | 2 |
| | 10 |
|
Regulatory required programs | (31 | ) | | — |
| | (31 | ) | | (46 | ) | | — |
| | (46 | ) | 11 |
| | — |
| | 11 |
| | (31 | ) | | — |
| | (31 | ) |
Other | 14 |
| | — |
| | 14 |
| | (7 | ) | | — |
| | (7 | ) | 14 |
| | (4 | ) | | 10 |
| | 14 |
| | — |
| | 14 |
|
Total increase (decrease) | $ | (55 | ) | | $ | 9 |
| | $ | (46 | ) | | $ | 114 |
| | $ | (9 | ) | | $ | 105 |
| $ | 26 |
| | $ | 21 |
| | $ | 47 |
| | $ | (55 | ) | | $ | 9 |
| | $ | (46 | ) |
Weather.The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended December 31, 2018 compared to the same period in 2017 RNF was increased by the impact of favorable weather conditions in PECO's service territory. For the year ended December 31, 2017 compared to the same period in 2016 and the year ended December 31, 2016 compared to the same period in 2015 Operating revenues net of purchased power and fuel expenseRNF was reduced by the impact of unfavorable weather conditions in PECO’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and cooling degree days in PECO’s service territory for the years ended December 31, 20172018 and December 31, 20162017 compared to the same periods in 20162017 and 2015,2016, respectively, and normal weather consisted of the following:
| | | For the Years Ended December 31, | | | | % Change | For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal |
Heating Degree-Days | 3,949 |
| | 4,041 |
| | 4,603 |
| | (2.3 | )% | | (14.2 | )% | 4,539 |
| | 3,949 |
| | 4,487 |
| | 14.9 | % | | 1.2 | % |
Cooling Degree-Days | 1,490 |
| | 1,726 |
| | 1,290 |
| | (13.7 | )% | | 15.5 | % | 1,584 |
| | 1,490 |
| | 1,411 |
| | 6.3 | % | | 12.3 | % |
| | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | % Change | For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | | Normal | | 2016 vs. 2015 | | 2016 vs. Normal | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,041 |
| | 4,245 |
| | 4,603 |
| | (4.8 | )% | | (12.2 | )% | 3,949 |
| | 4,041 |
| | 4,603 |
| | (2.3 | )% | | (14.2 | )% |
Cooling Degree-Days | 1,726 |
| | 1,720 |
| | 1,290 |
| | 0.3 | % | | 33.8 | % | 1,490 |
| | 1,726 |
| | 1,290 |
| | (13.7 | )% | | 15.5 | % |
Volume.The decrease Delivery volume, exclusive of the effects of weather, for the year ended December 31, 2018 compared to the same period in Operating revenues net2017, was driven by electric and primarily reflects the impact of purchased powermoderate economic and fuel expense relatedcustomer growth partially offset by the impact of energy efficiency initiatives on customer usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial classes to deliverythe residential class.
Delivery volume, exclusive of the effects of weather, for the year ended December 31, 2017 compared to the same period in 2016, was driven by electric and primarily reflects the impact of energy efficiency initiatives on customer usages for residential and small commercial and industrial electric classes, partially offset by solid customer growth. Additionally, the decrease represents a shift in the volume profile across classes from residential and small commercial and industrial to large commercial and industrial.
|
| | | | | | | | | | | | | | | | | | | | |
Electric Retail Deliveries to Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change |
Retail Deliveries (a) | | | | | | | | | | | | | |
Residential | 14,005 |
| | 13,024 |
| | 7.5 | % | | 3.5 | % | | 13,664 |
| | (4.7 | )% | | (1.8 | )% |
Small commercial & industrial | 8,177 |
| | 7,968 |
| | 2.6 | % | | 0.2 | % | | 8,099 |
| | (1.6 | )% | | (1.1 | )% |
Large commercial & industrial | 15,516 |
| | 15,426 |
| | 0.6 | % | | 0.4 | % | | 15,263 |
| | 1.1 | % | | 1.4 | % |
Public authorities & electric railroads | 761 |
| | 809 |
| | (5.9 | )% | | (5.6 | )% | | 890 |
| | (9.1 | )% | | (9.1 | )% |
Total electric retail deliveries | 38,459 |
| | 37,227 |
| | 3.3 | % | | 1.4 | % | | 37,916 |
| | (1.8 | )% | | (0.5 | )% |
__________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2018 | | 2017 | | 2016 |
Residential | 1,480,925 |
| | 1,469,916 |
| | 1,456,585 |
|
Small commercial & industrial | 152,797 |
| | 151,552 |
| | 150,142 |
|
Large commercial & industrial | 3,118 |
| | 3,112 |
| | 3,096 |
|
Public authorities & electric railroads | 9,565 |
| | 9,569 |
| | 9,823 |
|
Total | 1,646,405 |
| | 1,634,149 |
| | 1,619,646 |
|
|
| | | | | | | | | | | | | | | | | | | | |
Natural Gas Deliveries to customers (in mmcf) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather- Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change |
Retail Deliveries (a) | | | | | | | | | | | | | |
Residential | 43,450 |
| | 37,919 |
| | 14.6 | % | | 1.8 | % | | 36,872 |
| | 2.8 | % | | 0.6 | % |
Small commercial & industrial | 21,997 |
| | 20,515 |
| | 7.2 | % | | (0.4 | )% | | 19,525 |
| | 5.1 | % | | 1.9 | % |
Large commercial & industrial | 65 |
| | 23 |
| | 182.6 | % | | 175.8 | % | | 50 |
| | (54.0 | )% | | 28.3 | % |
Transportation | 26,595 |
| | 26,382 |
| | 0.8 | % | | (3.2 | )% | | 27,630 |
| | (4.5 | )% | | (2.3 | )% |
Total natural gas deliveries | 92,107 |
| | 84,839 |
| | 8.6 | % | | (0.2 | )% | | 84,077 |
| | 0.9 | % | | 0.1 | % |
__________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. |
|
| | | | | | | | |
| As of December 31, |
Number of Gas Customers | 2018 | | 2017 | | 2016 |
Residential | 482,255 |
| | 477,213 |
| | 472,606 |
|
Small commercial & industrial | 44,170 |
| | 43,887 |
| | 43,664 |
|
Large commercial & industrial | 1 |
| | 5 |
| | 4 |
|
Transportation | 754 |
| | 771 |
| | 790 |
|
Total | 527,180 |
| | 521,876 |
| | 517,064 |
|
Pricing for the year ended December 31, 2018 compared to the same period in 2017 reflects the anticipated pass back of the Tax Cuts and Jobs Act tax savings through customer rates.
The increase in Operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and customer growth partially offset by energy efficiency initiatives on customer usages for gas and residential and small commercial and industrial electric classes. Additionally, the increase represents a shift in the volume profile across classes from large commercial and industrial classes to residential and small commercial and industrial classes for electric.
Pricing.The increase in Operating revenues net of purchased power expense as a result of pricing for the year ended December 31, 2017 compared to the same period in 2016 reflects higher overall effective rates due to decreased usage in the residential and small commercial and industrial customer classes. Operating revenues net of fuel expense as a result of pricing remained relatively consistent.
The increase in Operating revenues net of purchased power and fuel expense as a result of pricing for the year ended December 31, 2016 compared to the same period in 2015 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 34 — Regulatory Matters for furtheradditional information.
Regulatory Required Programs.ProgramsThis represents the change in operating represent revenues 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. 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.revenues and wholesale transmission revenue.
Operating and Maintenance ExpenseSee Note 24—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | 2017 vs. 2016 | 2016 | | 2015 | | 2016 vs. 2015 |
Operating and maintenance expense—baseline | $ | 746 |
| | $ | 740 |
| | $ | 6 |
| | $ | 740 |
| | $ | 685 |
| | $ | 55 |
|
Operating and maintenance expense—regulatory required programs (a) | 60 |
| | 71 |
| | (11 | ) | | 71 |
| | 109 |
| | (38 | ) |
Total operating and maintenance expense | $ | 806 |
| | $ | 811 |
| | $ | (5 | ) | | $ | 811 |
| | $ | 794 |
| | $ | 17 |
|
__________
| |
(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 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | | | | | |
Labor, other benefits, contracting and materials | $ | 17 |
| | $ | 22 |
| | $ | 10 |
| | $ | 17 |
|
Storm-related costs(a) | (7 | ) | | (9 | ) | | 63 |
| | (7 | ) |
Pension and non-pension postretirement benefits expense | (3 | ) | | (4 | ) | | (7 | ) | | (3 | ) |
PHI merger integration costs | — |
| | 6 |
| | |
BSC costs | 4 |
| | 36 |
| (a) | — |
| | 4 |
|
Uncollectible accounts expense | (5 | ) | | 1 |
| | 7 |
| | (5 | ) |
Other | — |
| | 3 |
| | 9 |
| | — |
|
| 6 |
| | 55 |
| | 82 |
| | 6 |
|
Regulatory required programs | | | | | | | |
Smart meter | — |
| | (28 | ) | | |
Energy efficiency | (10 | ) | | (7 | ) | | 10 |
| | (10 | ) |
GSA | — |
| | (2 | ) | | |
Other | (1 | ) | | (1 | ) | | — |
| | (1 | ) |
| (11 | ) | | (38 | ) | | 10 |
| | (11 | ) |
Increase (decrease) in operating and maintenance expense | $ | (5 | ) | | $ | 17 |
| | $ | 92 |
| | $ | (5 | ) |
__________
(a) Primarily reflectsReflects increased information technology support servicescosts incurred from BSC during 2016.the Q1 2018 winter storms.
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015, consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Depreciation expense (a) | $ | 13 |
| | $ | 17 |
|
Regulatory asset amortization | 2 |
| | (1 | ) |
Increase in depreciation and amortization expense | $ | 15 |
|
| $ | 16 |
|
__________ |
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Depreciation expense | $ | 17 |
| | $ | 5 |
|
Regulatory asset amortization | (1 | ) | | 5 |
|
Increase in depreciation and amortization expense | $ | 16 |
|
| $ | 10 |
|
(a) Depreciation expense increased due to ongoing capital expenditures.Taxes Other Than Income
Taxes other than income which can vary increased for the year ended December 31, 2018, compared to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. the same period in 2017, primarily due to an increase in gross receipts tax driven by increased electric revenue.
Taxes other than income decreased for the year ended December 31, 2017, compared to the same period in 2016, primarily due to a decrease in gross receipts tax driven by decreases in electric revenue.
Taxes other than income increased for the year ended December 31, 2016, compared to the same period in 2015, primarily due to an increase in gross receipts tax driven by increases in electric revenue, which was impacted primarily by the new distribution rates that went into effect in January 2016.
Interest Expense, Net
The increase in Interest expense, net for the year ended December 31, 2017, compared to the same period in 2016, primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in September 2017.
The increase in Interest expense, net for the year ended December 31, 2016, compared to the same period in 2015, primarily reflects an increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.
Other, Net
Other, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.
Effective Income Tax Rate
PECO’s effective income tax rates were 1.3%, 19.3% and 25.4% for the years ended December 31, 2018, 2017 and 2016, and 2015 were 19.3%, 25.4% and 27.4%, respectively. The decrease is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussionadditional information of the change in effective income tax rates.
PECO Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather- Normal % Change |
Retail Deliveries (a) | | | | | | | | | | | | | |
Residential | 13,024 |
| | 13,664 |
| | (4.7 | )% | | (1.8 | )% | | 13,630 |
| | 0.2 | % | | 0.4 | % |
Small commercial & industrial | 7,968 |
| | 8,099 |
| | (1.6 | )% | | (1.1 | )% | | 8,118 |
| | (0.2 | )% | | 0.5 | % |
Large commercial & industrial | 15,426 |
| | 15,263 |
| | 1.1 | % | | 1.4 | % | | 15,365 |
| | (0.7 | )% | | (1.4 | )% |
Public authorities & electric railroads | 809 |
| | 890 |
| | (9.1 | )% | | (9.1 | )% | | 881 |
| | 1.0 | % | | 1.0 | % |
Total electric retail deliveries | 37,227 |
| | 37,916 |
| | (1.8 | )% | | (0.5 | )% | | 37,994 |
| | (0.2 | )% | | (0.3 | )% |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 1,469,916 |
| | 1,456,585 |
| | 1,444,338 |
|
Small commercial & industrial | 151,552 |
| | 150,142 |
| | 149,200 |
|
Large commercial & industrial | 3,112 |
| | 3,096 |
| | 3,091 |
|
Public authorities & electric railroads | 9,569 |
| | 9,823 |
| | 9,805 |
|
Total | 1,634,149 |
| | 1,619,646 |
| | 1,606,434 |
|
|
| | | | | | | | | | | | | | | | | |
Electric Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales (a) | | | | | | | | | |
Residential | $ | 1,505 |
| | $ | 1,631 |
| | (7.7 | )% | | $ | 1,599 |
| | 2.0 | % |
Small commercial & industrial | 401 |
| | 430 |
| | (6.7 | )% | | 428 |
| | 0.5 | % |
Large commercial & industrial | 223 |
| | 234 |
| | (4.7 | )% | | 221 |
| | 5.9 | % |
Public authorities & electric railroads | 30 |
| | 32 |
| | (6.3 | )% | | 31 |
| | 3.2 | % |
Total retail | 2,159 |
| | 2,327 |
| | (7.2 | )% | | 2,279 |
| | 2.1 | % |
Other revenue (b) | 216 |
| | 204 |
| | 5.9 | % | | 207 |
| | (1.4 | )% |
Total electric operating revenues (c) | $ | 2,375 |
| | $ | 2,531 |
| | (6.2 | )% | | $ | 2,486 |
| | 1.8 | % |
__________
| |
(a) | Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and transmission. |
| |
(b) | Other revenue includes transmission revenue from PJM and wholesale electric revenue. |
| |
(c) | Total electric revenue includes operating revenues from affiliates totaling $6 million, $7 million and $1 million for the years ended December 31, 2017, 2016, and 2015, respectively. |
PECO Gas Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Deliveries to customers (in mmcf) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather- Normal % Change |
Retail Deliveries (a) | | | | | | | | | | | | | |
Retail sales | 58,457 |
| | 56,447 |
| | 3.6 | % | | 1.2 | % | | 59,003 |
| | (4.3 | )% | | 1.5 | % |
Transportation and other | 26,382 |
| | 27,630 |
| | (4.5 | )% | | (2.3 | )% | | 27,879 |
| | (0.9 | )% | | (0.1 | )% |
Total natural gas deliveries | 84,839 |
| | 84,077 |
| | 0.9 | % | | 0.1 | % | | 86,882 |
| | (3.2 | )% | | 1.0 | % |
|
| | | | | | | | |
| As of December 31, |
Number of Gas Customers | 2017 | | 2016 | | 2015 |
Residential | 477,213 |
| | 472,606 |
| | 467,263 |
|
Commercial & industrial | 43,892 |
| | 43,668 |
| | 43,160 |
|
Total retail | 521,105 |
| | 516,274 |
| | 510,423 |
|
Transportation | 771 |
| | 790 |
| | 827 |
|
Total | 521,876 |
| | 517,064 |
| | 511,250 |
|
|
| | | | | | | | | | | | | | | | | |
Gas revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales (a) | | | | | | | | | |
Retail sales | $ | 462 |
| | $ | 430 |
| | 7.4 | % | | $ | 511 |
| | (15.9 | )% |
Transportation and other | 33 |
| | 33 |
| | — | % | | 35 |
| | (5.7 | )% |
Total natural gas operating revenues (b) | $ | 495 |
| | $ | 463 |
| | 6.9 | % | | $ | 546 |
| | (15.2 | )% |
__________
| |
(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) | Total natural gas revenue includes operating revenues from affiliates totaling $1 million for the years ended December 31, 2017, 2016 and 2015.
|
Results of Operations—BGE
| | | 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance | 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 3,176 |
| | $ | 3,233 |
| | $ | (57 | ) | | $ | 3,135 |
| | $ | 98 |
| $ | 3,169 |
| | $ | 3,176 |
| | $ | (7 | ) | | $ | 3,233 |
| | $ | (57 | ) |
Purchased power and fuel expense | 1,133 |
| | 1,294 |
| | 161 |
| | 1,305 |
| | 11 |
| 1,182 |
| | 1,133 |
| | (49 | ) | | 1,294 |
| | 161 |
|
Revenues net of purchased power and fuel expense(a) | 2,043 |
| | 1,939 |
| | 104 |
| | 1,830 |
| | 109 |
| 1,987 |
| | 2,043 |
| | (56 | ) | | 1,939 |
| | 104 |
|
Other operating expenses | | | | | | | | | | | | | | | | | | |
Operating and maintenance | 716 |
| | 737 |
| | 21 |
| | 683 |
| | (54 | ) | 777 |
| | 716 |
| | (61 | ) | | 737 |
| | 21 |
|
Depreciation and amortization | 473 |
| | 423 |
| | (50 | ) | | 366 |
| | (57 | ) | 483 |
| | 473 |
| | (10 | ) | | 423 |
| | (50 | ) |
Taxes other than income | 240 |
| | 229 |
| | (11 | ) | | 224 |
| | (5 | ) | 254 |
| | 240 |
| | (14 | ) | | 229 |
| | (11 | ) |
Total other operating expenses | 1,429 |
| | 1,389 |
| | (40 | ) | | 1,273 |
| | (116 | ) | 1,514 |
| | 1,429 |
| | (85 | ) | | 1,389 |
| | (40 | ) |
Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | (1 | ) | 1 |
| | — |
| | 1 |
| | — |
| | — |
|
Operating income | 614 |
| | 550 |
| | 64 |
| | 558 |
| | (8 | ) | 474 |
| | 614 |
| | (140 | ) | | 550 |
| | 64 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | | | |
Interest expense, net | (105 | ) | | (103 | ) | | (2 | ) | | (99 | ) | | (4 | ) | (106 | ) | | (105 | ) | | (1 | ) | | (103 | ) | | (2 | ) |
Other, net | 16 |
| | 21 |
| | (5 | ) | | 18 |
| | 3 |
| 19 |
| | 16 |
| | 3 |
| | 21 |
| | (5 | ) |
Total other income and (deductions) | (89 | ) | | (82 | ) | | (7 | ) | | (81 | ) | | (1 | ) | (87 | ) | | (89 | ) | | 2 |
| | (82 | ) | | (7 | ) |
Income before income taxes | 525 |
| | 468 |
| | 57 |
| | 477 |
| | (9 | ) | 387 |
| | 525 |
| | (138 | ) | | 468 |
| | 57 |
|
Income taxes | 218 |
| | 174 |
| | (44 | ) | | 189 |
| | 15 |
| 74 |
| | 218 |
| | 144 |
| | 174 |
| | (44 | ) |
Net income | 307 |
| | 294 |
| | 13 |
| | 288 |
| | 6 |
| 313 |
| | 307 |
| | 6 |
| | 294 |
| | 13 |
|
Preference stock dividends | — |
| | 8 |
| | 8 |
| | 13 |
| | 5 |
| — |
| | — |
| | — |
| | 8 |
| | 8 |
|
Net income attributable to common shareholder | $ | 307 |
| | $ | 286 |
| | $ | 21 |
| | $ | 275 |
| | $ | 11 |
| $ | 313 |
| | $ | 307 |
| | $ | 6 |
| | $ | 286 |
| | $ | 21 |
|
__________Year Ended December 31, 2018 Compared to Year Ended December 31, 2017.
| |
(a) | BGE 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. BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However, revenues net of purchased power and fuel expense figures are not a presentation 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 Attributableincome attributable to Common Shareholdercommon shareholder increased by $6 million primarily due to an increase in transmission formula rate revenues and the absence of the 2017 impairment of certain transmission-related income tax regulatory assets offset by increased storm restoration costs as a result of storms in March 2018 and September 2018. The TCJA did not significantly impact Net income attributable to common shareholder as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016.Net income attributable to common shareholder was higher primarily due to an increase in Revenues net of purchased power and fuel expense and lower Operating and maintenance expense, partially offset increased by higher Depreciation and amortization expense and higher income tax expense. The increase in Revenues net of purchased power and fuel expense was$21 million primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016, and an increase in transmission formula rate revenues. The lower Operating and maintenance expense was primarily due torevenues, the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC, and
decreased storm costs in 20172017. These increases were partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute. These items were partially offset by an increase in Depreciation and amortization expense primarily related todispute, the initiation of cost recovery of the AMI programs under the distribution rate orders and the impacts of increased capital investment, and higher income tax expense primarily resulting from higher taxable income as well as a 2016 favorable adjustment, and the 2017 impairment of certain transmission-related income tax regulatory assets.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015.Net income attributable to common shareholder was higher primarily due to lower income tax expense and decreased preference stock dividends partially offset by slightly lower operating income. The lower income tax expense was driven by a one-time adjustment associated with transmission-related regulatory assets. The slight decrease in operating income was driven by an increase in Operating and maintenance expense as a result of cost disallowances which reduced certain regulatory assets and other long-lived assets stemming from the distribution rate orders issued by the MDPSC in June 2016 and July 2016 and increased storm costs. This increase in Operating and maintenance expense was offset by an increase in Revenues net of purchased power and fuel expense, primarily 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.
Revenues Net of Purchased Power and Fuel Expense
Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased power and fuel expense, such as commodity procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased power and fuel expense are affected by fluctuationsparticipation 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 purchasedcustomer choice programs. BGE recovers electricity, natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs, respectively.other procurement costs from customers without mark-up. Therefore, fluctuations in electric supply and natural gas procurementthese costs have no impact on Revenues net of purchased power and fuel expense.RNF.
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 supplier for electricity and/or natural gas. All BGE customersCustomers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. The customers'Customer choice of suppliers doesprograms do not impact the volume of deliveries or RNF but does affect revenue collected from customersimpact Operating revenues related to supplied electricity and natural gas.
Retail deliveries purchased from competitiveThe changes in RNF consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2018 vs. 2017 | | 2017 vs. 2016 |
| Increase (Decrease) | | Increase (Decrease) |
| Electric | | Gas | | Total | | Electric | | Gas | | Total |
Distribution rate increase (decrease) | $ | (62 | ) | | $ | (28 | ) | | $ | (90 | ) | | $ | 21 |
| | $ | 29 |
| | $ | 50 |
|
Regulatory required programs | 2 |
| | 2 |
| | 4 |
| | 17 |
| | 3 |
| | 20 |
|
Transmission revenue | 15 |
| | — |
| | 15 |
| | 18 |
| | — |
| | 18 |
|
Other, net | 5 |
| | 10 |
| | 15 |
| | 5 |
| | 11 |
| | 16 |
|
Total (decrease) increase | $ | (40 | ) | | $ | (16 | ) |
| $ | (56 | ) | | $ | 61 |
| | $ | 43 |
| | $ | 104 |
|
Revenue Decoupling. The demand for electricity and natural gas suppliers (asis affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a percentageresult of kWh and mmcf sales, respectively)a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the yearsnumber of customers.
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2018 | | 2017 | | 2016 |
Residential | 1,168,372 |
| | 1,160,783 |
| | 1,150,096 |
|
Small commercial & industrial | 113,915 |
| | 113,594 |
| | 113,230 |
|
Large commercial & industrial | 12,253 |
| | 12,155 |
| | 12,053 |
|
Public authorities & electric railroads | 262 |
| | 272 |
| | 280 |
|
Total | 1,294,802 |
| | 1,286,804 |
| | 1,275,659 |
|
|
| | | | | | | | |
| As of December 31, |
Number of Gas Customers | 2018 | | 2017 | | 2016 |
Residential | 633,757 |
| | 629,690 |
| | 623,647 |
|
Small commercial & industrial | 38,332 |
| | 38,392 |
| | 37,941 |
|
Large commercial & industrial | 5,954 |
| | 5,855 |
| | 6,314 |
|
Total | 678,043 |
| | 673,937 |
| | 667,902 |
|
Distribution Revenues decreased during the year ended December 31, 2018, compared to the same period in 2017, 2016primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate and 2015 consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31,
|
| 2017 | | 2016 | | 2015 |
Electric | 60 | % | | 59 | % | | 61 | % |
Natural Gas | 55 | % | | 57 | % | | 56 | % |
The number of retail customers purchasing electricity and natural gas from competitive suppliers at December 31, 2017, 2016 and 2015 consisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of Customers | | % of total retail customers | | Number of Customers | | % of total retail customers | | Number of Customers | | % of total retail customers |
Electric | 341,000 |
| | 27 | % | | 337,000 |
| | 27 | % | | 343,000 |
| | 27 | % |
Natural Gas | 151,000 |
| | 22 | % | | 151,000 |
| | 23 | % | | 154,000 |
| | 23 | % |
The changes in BGE’s Operating revenues net of purchased power and fuel expense forincreased during the year ended December 31, 2017, compared to the same period in 2016, and for the year ended December 31, 2016 compared to the same period in 2015, respectively, consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2017 vs. 2016 | | 2016 vs. 2015 |
| Increase (Decrease) | | Increase (Decrease) |
| Electric | | Gas | | Total | | Electric | | Gas | | Total |
Distribution rate increase | $ | 21 |
| | $ | 29 |
| | $ | 50 |
| | $ | 24 |
| | $ | 22 |
| | $ | 46 |
|
Regulatory required programs | 17 |
| | 3 |
| | 20 |
| | 10 |
| | (5 | ) | | 5 |
|
Transmission revenue | 18 |
| | — |
| | 18 |
| | 30 |
| | — |
| | 30 |
|
Other, net | 5 |
| | 11 |
| | 16 |
| | 24 |
| | 4 |
| | 28 |
|
Total increase | $ | 61 |
| | $ | 43 |
|
| $ | 104 |
| | $ | 88 |
| | $ | 21 |
| | $ | 109 |
|
Distribution Rate Increase. During the years ended December 31, 2017 and December 31, 2016, the increases in distribution revenues were primarily due to the impact of the electric and natural gas distribution rate changes that became effective in June 2016 in accordance with the electric and natural gas distribution rate case orders in June 2016 and July 2016. See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Revenue Decoupling.Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism. The 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 fluctuations in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved distribution charges 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 volatility in 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.riders are
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 30-year period in BGE’s service territory. The changes in heating and cooling degree days in BGE’s service territory for the year ended December 31, 2017 compared to the same period in 2016 and for the year ended December 31, 2016 compared to the same period in 2015, respectively, and normal weather consisted of the following:
|
| | | | | | | | | | | | | | |
| For the Year Ended December 31, | | Normal | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,190 |
| | 4,427 |
| | 4,666 |
| | (5.4 | )% | | (10.2 | )% |
Cooling Degree-Days | 940 |
| | 998 |
| | 875 |
| | (5.8 | )% | | 7.4 | % |
|
| | | | | | | | | | | | | | |
| For the Year Ended December 31, | | Normal | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | 2016 vs. 2015 | | 2016 vs. Normal |
Heating Degree-Days | 4,427 |
| | 4,666 |
| | 4,684 |
| | (5.1 | )% | | (5.5 | )% |
Cooling Degree-Days | 998 |
| | 924 |
| | 876 |
| | 8.0 | % | | 13.9 | % |
Regulatory Required Programs.Revenue from regulatory required programs are billings for the costs of various legislative and/or regulatory programs that are recoverable from customers on a full and current basis. These programs are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income in BGE's Consolidated Statements of Operations and Comprehensive Income.income.
Transmission Revenue.Under a FERC approved formula, transmission revenue varies from year to year based upon rate adjustments to reflect fluctuations in the underlying costs, capital investments being recovered and other billing determinants. Duringthe highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased during the years ended December 31, 20172018 and 2016, the increase in transmission revenue was2017 primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and Maintenance Expensemaintenance expense below and Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other Net.revenue Other netincludes revenue which can vary from periodrelated to period, primarily includes late payment feescharges, mutual assistance revenues, off-system sales and other miscellaneous revenue such as service application fees, assistance providedfees.
See Note 24 — Segment Information of the Combined Notes to other utilities throughConsolidated Financial Statements for the presentation of BGE's mutual assistance program and recoveries of electric supply and natural gas procurement costs.revenue disaggregation.
The changes in Operating and Maintenance Expensemaintenance expense consisted of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | 2017 vs. 2016 | | 2016 | | 2015 | | 2016 vs. 2015 |
Operating and maintenance expense—baseline | $ | 672 |
| | $ | 701 |
| | $ | (29 | ) | | $ | 701 |
| | $ | 636 |
| | $ | 65 |
|
Operating and maintenance expense—regulatory required programs(a) | 44 |
| | 36 |
| | 8 |
| | 36 |
| | 47 |
| | (11 | ) |
Total operating and maintenance expense | $ | 716 |
| | $ | 737 |
| | $ | (21 | ) | | $ | 737 |
| | $ | 683 |
| | $ | 54 |
|
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | |
Impairment on long-lived assets and losses on regulatory assets(a) | $ | — |
| | $ | (50 | ) |
Labor, other benefits, contracting and materials | 18 |
| | (11 | ) |
Pension and non-pension postretirement benefits expense | (2 | ) | | — |
|
Storm-related costs(b) | 39 |
| | (13 | ) |
Uncollectible accounts expense | 2 |
| | 7 |
|
BSC costs | 7 |
| | 16 |
|
Conduit lease settlement(c) | — |
| | 15 |
|
Other | 3 |
| | 7 |
|
| $ | 67 |
| | $ | (29 | ) |
Regulatory Required Programs | | | |
Other | (6 | ) | | 8 |
|
Total (decrease) increase | $ | 61 |
| | $ | (21 | ) |
__________
| |
(a) | 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 revenues. |
The changes in Operating and maintenance expense for the year ended December 31, 2017 compared to the same period in 2016 and the year ended December 31, 2016 compared to the same period in 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Baseline | | | |
Impairment on long-lived assets and losses on regulatory assets(a) | $ | (50 | ) | | $ | 52 |
|
Labor, other benefits, contracting and materials | (11 | ) | | 7 |
|
Storm-related costs | (13 | ) | | 18 |
|
Uncollectible accounts expense | 7 |
| | (14 | ) |
BSC costs | 16 |
| | 11 |
|
Conduit lease settlement(b) | 15 |
| | (15 | ) |
Other | 7 |
| | 6 |
|
| $ | (29 | ) | | $ | 65 |
|
Regulatory Required Programs | | | |
Other | 8 |
| | (11 | ) |
| 8 |
| | (11 | ) |
Total (decrease) increase | $ | (21 | ) | | $ | 54 |
|
__________
| |
(a) | See Note 34 —Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. information on Smart Meter and Smart Grid Investments. |
| |
(b) | Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018. |
| |
(c) | See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information. |
Depreciation and Amortization
The changes in Depreciation and amortization expense for the year ended December 31, 2017 compared to the same period in 2016 and December 31, 2016 compared to the same period in 2015 consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Depreciation expense(a) | $ | 13 |
| | $ | 10 |
| $ | 25 |
| | $ | 13 |
|
Regulatory asset amortization(b) | 25 |
| | 31 |
| (24 | ) | | 25 |
|
Regulatory required programs(c) | 12 |
| | 16 |
| 9 |
| | 12 |
|
Increase in depreciation and amortization expense | $ | 50 |
| | $ | 57 |
| $ | 10 |
| | $ | 50 |
|
__________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization increaseddecreased for the year ended December 31, 2018 compared to the same period in 2017, primarily due to an increasecertain regulatory assets that became fully amortized as of December 31, 2017 and increased for the year ended December 31, 2017 compared to the same period in regulatory asset amortization related2016, primarily due to energy efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in June 2016. See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information. |
| |
(c) | Depreciation and amortization expenses for regulatory required programs 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. |
Taxes Other Than Income
Taxes other than income which can varyincreased for the year ended December 31, 2018 compared to the same period to period, include municipalin 2017, and state utility taxes, real estate taxes and payroll taxes. Taxes other than income taxes increased for the year ended December 31, 2017 compared to the same period in 2016, and for the year ended December 31, 2016 compared to the same period in 2015, primarily due to an increase in property taxes.
Interest Expense, Net
Interest expense, net remained relatively consistentEffective income tax rates were 19.1%, 41.5% and 37.2% for the years ended December 31, 2018, 2017 and 2016, respectively. Income taxes decreased for the year ended December 31, 20172018 compared to the same period in 2016, and for the year ended December 31, 2016 compared2017, primarily due to the same period in 2015.
Other, Net
Other, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.
Effective Income Tax Rate
BGE’s effectivelower federal income tax rates forrate as a result of the years ended December 31, 2017, 2016 and 2015 were 41.5%, 37.2% and 39.6%, respectively.TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
BGE Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather- Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Residential | 12,094 |
| | 12,740 |
| | (5.1 | )% | | (2.8 | )% | | 12,598 |
| | 1.1 | % | | (3.2 | )% |
Small commercial & industrial | 2,921 |
| | 3,040 |
| | (3.9 | )% | | (4.9 | )% | | 3,119 |
| | (2.5 | )% | | 2.7 | % |
Large commercial & industrial | 13,688 |
| | 13,957 |
| | (1.9 | )% | | (2.4 | )% | | 14,293 |
| | (2.4 | )% | | (1.6 | )% |
Public authorities & electric railroads | 268 |
| | 283 |
| | (5.3 | )% | | (3.0 | )% | | 294 |
| | (3.7 | )% | | (8.9 | )% |
Total electric deliveries | 28,971 |
| | 30,020 |
| | (3.5 | )% | | (2.8 | )% | | 30,304 |
| | (0.9 | )% | | (1.9 | )% |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 1,160,783 |
| | 1,150,096 |
| | 1,137,934 |
|
Small commercial & industrial | 113,594 |
| | 113,230 |
| | 113,138 |
|
Large commercial & industrial | 12,155 |
| | 12,053 |
| | 11,906 |
|
Public authorities & electric railroads | 272 |
| | 280 |
| | 285 |
|
Total | 1,286,804 |
| | 1,275,659 |
| | 1,263,263 |
|
|
| | | | | | | | | | | | | | | | | |
Electric Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Residential | $ | 1,428 |
| | $ | 1,554 |
| | (8.1 | )% | | $ | 1,449 |
| | 7.2 | % |
Small commercial & industrial | 266 |
| | 277 |
| | (4.0 | )% | | 273 |
| | 1.5 | % |
Large commercial & industrial | 450 |
| | 449 |
| | 0.2 | % | | 469 |
| | (4.3 | )% |
Public authorities & electric railroads | 31 |
| | 35 |
| | (11.4 | )% | | 32 |
| | 9.4 | % |
Total retail | 2,175 |
| | 2,315 |
| | (6.0 | )% | | 2,223 |
| | 4.1 | % |
Other revenue(b)(c) | 314 |
| | 294 |
| | 6.8 | % | | 267 |
| | 10.1 | % |
Total electric revenue
| $ | 2,489 |
| | $ | 2,609 |
| | (4.6 | )% | | $ | 2,490 |
| | 4.8 | % |
__________
| |
(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) | Other revenue primarily includes wholesale transmission revenue and late payment charges. |
| |
(c) | Includes operating revenues from affiliates totaling $5 million, $7 million and less than $1 million for the years ended 2017, 2016 and 2015, respectively. |
BGE Natural Gas Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Deliveries to customers (in mmcf) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather- Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather- Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Retail sales | 89,337 |
| | 96,808 |
| | (7.7 | )% | | (4.2 | )% | | 96,618 |
| | 0.2 | % | | 3.5 | % |
Transportation and other(b) | 3,615 |
| | 5,977 |
| | (39.5 | )% | | n/a |
| | 6,238 |
| | (4.2 | )% | | n/a |
|
Total natural gas deliveries | 92,952 |
| | 102,785 |
| | (9.6 | )% | | (4.2 | )% | | 102,856 |
| | (0.1 | )% | | 3.5 | % |
|
| | | | | | | | |
| As of December 31, |
Number of Gas Customers | 2017 | | 2016 | | 2015 |
Residential | 629,690 |
| | 623,647 |
| | 616,994 |
|
Commercial & industrial | 44,247 |
| | 44,255 |
| | 44,119 |
|
Total | 673,937 |
| | 667,902 |
| | 661,113 |
|
|
| | | | | | | | | | | | | | | | | |
Natural Gas revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Retail sales | $ | 655 |
| | $ | 593 |
| | 10.5 | % | | $ | 607 |
| | (2.3 | )% |
Transportation and other(b) | 32 |
| | 31 |
| | 3.2 | % | | 38 |
| | (18.4 | )% |
Total natural gas revenues(c)
| $ | 687 |
| | $ | 624 |
| | 10.1 | % | | $ | 645 |
| | (3.3 | )% |
__________
| |
(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. For customers purchasing natural gas from BGE, revenue also reflects the cost of natural gas. |
| |
(b) | Transportation and other natural gas revenue includes off-system revenue of 3,615 mmcfs ($21 million), 5,977 mmcfs ($23 million), and 6,238 mmcfs ($35 million) for the years ended 2017, 2016 and 2015, respectively. |
| |
(c) | Includes operating revenues from affiliates totaling $11 million, $14 million, and $14 million for the years ended 2017, 2016 and 2015, respectively. |
Results of Operations—PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below.ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's corporate operations include interest costs from various financing activities. For "Predecessor" reporting periods, PHI's results of operations also include the results of PES and PCI. See Note 2524 — 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.
The following tables sets forth PHI's GAAP Net Income (Loss) by Registrant. As a result of the PHI Merger, the following consolidated financial resultstables present two separate reporting periods for 2016. The "Predecessor" reporting periods represent PHI's results of operations for the period of January 1, 2016 to March 23, 2016 and the year ended December 31, 2015.2016. The "Successor" reporting periods represents PHI's results of operations for the yearyears ended December 31, 2018 and 2017 and for the period ofas well as March 24, 2016 to December 31, 2016. All amounts presented below are beforeSee the impactresults of income taxes, except as noted.operations for Pepco, DPL, and ACE for additional information by segment.
|
| | | | | | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | March 24 to December 31, | | | January 1 to March 23, |
| 2018 | | 2017 | | | 2016 | | | 2016 |
PHI | $ | 398 |
| | $ | 362 |
| | $ | 36 |
| | $ | (61 | ) | | | $ | 19 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Favorable (unfavorable) 2018 vs. 2017 variance | | For the Years Ended December 31, | | Favorable (unfavorable) 2017 vs. 2016 variance |
| 2018 | | 2017 | | | 2017 | | 2016 | |
Pepco | $ | 210 |
| | $ | 205 |
| | $ | 5 |
| | $ | 205 |
| | $ | 42 |
| | $ | 163 |
|
DPL | 120 |
| | 121 |
| | (1 | ) | | 121 |
| | (9 | ) | | 130 |
|
ACE | 75 |
| | 77 |
| | (2 | ) | | 77 |
| | (42 | ) | | 119 |
|
Other(a) | (7 | ) | | (41 | ) | | 34 |
| | (41 | ) | | n/a |
| | n/a |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, | | For the Year Ended December 31, |
| 2017 | | 2016 | | | 2016 | | 2015 |
Operating revenues | $ | 4,679 |
| | $ | 3,643 |
| | | $ | 1,153 |
| | $ | 4,935 |
|
Purchased power and fuel | 1,716 |
| | 1,447 |
| | | 497 |
| | 2,073 |
|
Revenues net of purchased power and fuel expense(a) | 2,963 |
| | 2,196 |
| | | 656 |
|
| 2,862 |
|
Other operating expenses | | | | | | | | |
Operating and maintenance | 1,068 |
| | 1,233 |
| | | 294 |
| | 1,156 |
|
Depreciation and amortization | 675 |
| | 515 |
| | | 152 |
| | 624 |
|
Taxes other than income | 452 |
| | 354 |
| | | 105 |
| | 455 |
|
Total other operating expenses | 2,195 |
| | 2,102 |
| | | 551 |
|
| 2,235 |
|
Gain (loss) on sales of assets | 1 |
| | (1 | ) | | | — |
| | 46 |
|
Operating income | 769 |
| | 93 |
| | | 105 |
| | 673 |
|
Other income and (deductions) | | | | | | | | |
Interest expense, net | (245 | ) | | (195 | ) | | | (65 | ) | | (280 | ) |
Other, net | 54 |
| | 44 |
| | | (4 | ) | | 88 |
|
Total other income and (deductions) | (191 | ) | | (151 | ) | | | (69 | ) |
| (192 | ) |
Income (loss) before income taxes | 578 |
| | (58 | ) | | | 36 |
| | 481 |
|
Income taxes | 217 |
| | 3 |
| | | 17 |
| | 163 |
|
Equity in earnings of unconsolidated affiliates | 1 |
| | — |
| | | — |
| | — |
|
Net income (loss) from continuing operations | 362 |
| | (61 | ) | | | 19 |
|
| 318 |
|
Net income from discontinued operations | — |
| | — |
| | | — |
| | 9 |
|
Net income (loss) attributable to membership interest/common shareholders | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
| | $ | 327 |
|
___________________
| |
(a) | Primarily includes eliminating and consolidating adjustments, PHI’s corporate operations, shared service entities and other financing activities. Not included for 2016 due to PHI 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 isPredecessor periods 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.being comparable. |
Successor Year Ended December 31, 2018 Compared to Successor Year Ended December 31, 2017
PHI's 2017. Net income was $362 increased by $36 million for the year ended December 31, 2017. There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor year except forprimarily due to distribution rate increases (not reflecting the impact of increases in electric distributionthe TCJA), favorable weather and natural gas rates within Revenue net of purchased power expense (Pepco electric distribution rates effective November 2016 and October 2017 in Maryland, Pepco electric distribution rates effective August 2017 involume, the District of Columbia, DPL electric distribution rates effective February 2017 in Maryland, DPL electric distribution and natural gas rates effective July 2016 and December 2016 in Delaware, and ACE electric distribution rates effective August 2016 and
October 2017 in New Jersey). Operating and maintenance expense incurred included the deferral of merger-related, rate case, and customer billing system costs to regulatory assets and lower uncollectible accounts expense, partially offset by a pre-tax impairment charge of $25 million. Income taxes expense incurred included unrecognized tax benefits of $59 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarterabsence of 2017 and was offset by a $27 million December 2017 impairmentimpairments of certain transmission-related income tax regulatory assets and the one-time non-cash impactsDC sponsorship intangible asset, partially offset by an increase in asset retirement obligations primarily related to asbestos identified at the Buzzard Point property and the deferral of $35 million associated with the Tax Cuts and Jobs Actaccumulated merger integration cost as regulatory assets in 2017. For more information on 2017 results please refer to Results of Operations for Pepco, DPL, and ACE.
PHI's effectiveThe TCJA did not significantly impact Net income as the favorable tax rate forimpacts were predominantly offset by lower revenues resulting from the year ended December 31, 2017 was 37.5%. See Note 14 — Income Taxespass back of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of effective income tax savings through customer rates.
Successor Period of March 24, 2016 to December 31, 2016
PHI's . Net loss for the Successor period of March 24, 2016 to December 31, 2016 was $61 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period March 24, 2016 to December 31, 2016 except for the pre-tax recording of $392 million of non-recurring merger-related costs including merger integration and merger commitments within Operating and maintenance expense. For more information on 2016 results please refer to Results of Operations for Pepco, DPL and ACE.
PHI's effective income tax rate for the period of March 24, 2016 to December 31, 2016 was (5.2)%. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period ofJanuary 1, 2016 to March 23, 2016
PHI's 2016. Net income for the Predecessor period of January 1, 2016 to March 23, 2016 was $19 million. There were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23, 2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of preferred stock derivative expense within Other, net.
PHI's effective income tax rate for the period
Results of January 1, 2016 to March 23, 2016 was 47.2%. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.Operations—Pepco
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 2,239 |
| | $ | 2,158 |
| | $ | 81 |
| | $ | 2,186 |
| | $ | (28 | ) |
Purchased power expense | 654 |
| | 614 |
| | (40 | ) | | 706 |
| | 92 |
|
Revenues net of purchased power expense | 1,585 |
| | 1,544 |
| | 41 |
| | 1,480 |
| | 64 |
|
Other operating expenses | | | | | | | | | |
Operating and maintenance | 501 |
| | 454 |
| | (47 | ) | | 642 |
| | 188 |
|
Depreciation and amortization | 385 |
| | 321 |
| | (64 | ) | | 295 |
| | (26 | ) |
Taxes other than income | 379 |
| | 371 |
| | (8 | ) | | 377 |
| | 6 |
|
Total other operating expenses | 1,265 |
| | 1,146 |
| | (119 | ) | | 1,314 |
| | 168 |
|
Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | 8 |
| | (7 | ) |
Operating income | 320 |
| | 399 |
| | (79 | ) | | 174 |
| | 225 |
|
Other income and (deductions) | | | | | | | | | |
Interest expense, net | (128 | ) | | (121 | ) | | (7 | ) | | (127 | ) | | 6 |
|
Other, net | 31 |
| | 32 |
| | (1 | ) | | 36 |
| | (4 | ) |
Total other income and (deductions) | (97 | ) | | (89 | ) | | (8 | ) | | (91 | ) | | 2 |
|
Income before income taxes | 223 |
| | 310 |
| | (87 | ) | | 83 |
| | 227 |
|
Income taxes | 13 |
| | 105 |
| | 92 |
| | 41 |
| | (64 | ) |
Net income | $ | 210 |
| | $ | 205 |
| | $ | 5 |
| | $ | 42 |
| | $ | 163 |
|
Year Ended December 31, 2015
PHI's Net income was $327 million for the year ended2018 Compared to Year Ended December 31, 2015. There were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor year except for2017.Net income increased by $5 million primarily due to higher electric distribution base rates (not reflecting the impact of increasesthe TCJA) in Maryland that became effective October 2017 and June 2018 and higher electric distribution base rates within Revenue net(not reflecting the impact of purchased power expense (Pepco electric distribution rates effective April 2014the TCJA) in the District of Columbia Pepco electric distribution ratesthat became effective July 2014 in Maryland,August 2017 and ACE electric distribution rates effective September 2014),August 2018, partially offset by Operatingan increase in asset retirement obligations related primarily to the Buzzard Point property, deferral of accumulated merger integration costs as regulatory assets in 2017 and maintenance costs incurredhigher regulatory asset amortization due to additional regulatory assets related to rate case activity. The TCJA did not significantly impact Net income as the implementationfavorable tax impacts were predominantly offset by lower revenues resulting from pass back of a newtax savings through customer information system for Pepco, DPL, and ACE in 2015. Gain (loss) on sales of assets were $46 million, primarily due to 2015 gains recorded at Pepco associated with the sale of unimproved land, held as non-utility property.
PHI's effective income tax rate for the year ended December 31, 2015 was 33.9%. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Results of Operations—Pepco
|
| | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance |
Operating revenues | $ | 2,158 |
| | $ | 2,186 |
| | $ | (28 | ) | | $ | 2,129 |
| | $ | 57 |
|
Purchased power expense | 614 |
| | 706 |
| | 92 |
| | 719 |
| | 13 |
|
Revenues net of purchased power expense(a) | 1,544 |
| | 1,480 |
| | 64 |
| | 1,410 |
| | 70 |
|
Other operating expenses | | | | | | | | | |
Operating and maintenance | 454 |
| | 642 |
| | 188 |
| | 439 |
| | (203 | ) |
Depreciation and amortization | 321 |
| | 295 |
| | (26 | ) | | 256 |
| | (39 | ) |
Taxes other than income | 371 |
| | 377 |
| | 6 |
| | 376 |
| | (1 | ) |
Total other operating expenses | 1,146 |
| | 1,314 |
| | 168 |
| | 1,071 |
| | (243 | ) |
Gain on sales of assets | 1 |
| | 8 |
| | (7 | ) | | 46 |
| | (38 | ) |
Operating income | 399 |
| | 174 |
| | 225 |
| | 385 |
| | (211 | ) |
Other income and (deductions) | | | | | | | | | |
Interest expense, net | (121 | ) | | (127 | ) | | 6 |
| | (124 | ) | | (3 | ) |
Other, net | 32 |
| | 36 |
| | (4 | ) | | 28 |
| | 8 |
|
Total other income and (deductions) | (89 | ) | | (91 | ) | | 2 |
| | (96 | ) | | 5 |
|
Income before income taxes | 310 |
| | 83 |
| | 227 |
| | 289 |
| | (206 | ) |
Income taxes | 105 |
| | 41 |
| | (64 | ) | | 102 |
| | 61 |
|
Net income | $ | 205 |
| | $ | 42 |
| | $ | 163 |
| | $ | 187 |
| | $ | (145 | ) |
__________
| |
(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
Year Ended December 31, 2017Compared to Year Ended December 31, 2016. Pepco's Net income for the year ended December 31, 2017, was higher than the same period in 2016, increased by $163 million primarily due to a decrease in Operating and maintenance expense due to merger-related costs recognized in March 2016, and an increasehigher electric distribution base rates in Revenue net of purchased power expense as a result of the distribution rate increases approved by the MDPSCMaryland that became effective November 2016 and October 2017 and anhigher electric distribution rate increase approved bybase rates in the DCPSCDistrict of Columbia that became effective August 2017, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016. Income taxes expense incurred included unrecognized tax benefits of $21 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the $14 million December 2017 impairment of certain transmission-relatedtransmission related income tax regulatory assets and the one-time non-cash impacts of $8 million associated with the Tax Cuts and Jobs Act in 2017.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Pepco's Net income for the year ended December 31, 2016, was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense due to merger-related costs.assets.
Operating RevenueRevenues Net of Purchased Power Expense
Expense. There are certain drivers of 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 regulatedare fully offset by FERC. Transmission rates are updated annually basedtheir impact on a FERC-approved formula methodology.
Electric revenues and purchasedPurchased power expense, are also affected bysuch as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up. Therefore, fluctuations in participation in the Customer Choice Program. All Pepco customersthese costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. The customers'Customer choice of supplier doesprograms do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energy service.electricity.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31, 2017, 2016 and 2015 respectively,The changes in RNF consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Electric | 66 | % | | 65 | % | | 65 | % |
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Volume | $ | 12 |
| | $ | 16 |
|
Distribution revenue | (3 | ) | | 66 |
|
Regulatory required programs | 35 |
| | (12 | ) |
Transmission revenues | — |
| | 9 |
|
Other | (3 | ) | | (15 | ) |
Total increase | $ | 41 |
| | $ | 64 |
|
Retail customers purchasingRevenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric generation from competitive electric generation suppliers at December 31, 2017, 2016distribution in both Maryland and 2015 consisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 179,184 |
| | 21 | % | | 176,372 |
| | 21 | % | | 173,222 |
| | 21 | % |
Retail deliveries purchased from competitive electric generation suppliers represented 73% of Pepco’s retail kWh sales to the District of Columbia customers and 60%are not impacted by abnormal weather or usage per customer as a result of Pepco’s retail kWh sales to Maryland customersa bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2017; 73% of Pepco’s retail kWh sales2018 compared to the Districtsame period in 2017, and for the year ended 2017 compared to the same period in 2016 primarily due to the impact of Columbia customers and 59% of Pepco’s retail kWh sales to Maryland customersresidential customer growth.
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2018 | | 2017 | | 2016 |
Residential | 807,442 |
| | 792,211 |
| | 780,652 |
|
Small commercial & industrial | 54,306 |
| | 53,489 |
| | 53,529 |
|
Large commercial & industrial | 22,022 |
| | 21,732 |
| | 21,391 |
|
Public authorities & electric railroads | 150 |
| | 144 |
| | 130 |
|
Total | 883,920 |
| | 867,576 |
| | 855,702 |
|
Distribution Revenues decreased for the year ended December 31, 2016;2018 compared to the same period in 2017 primarily due to the impact of reduced distribution rates to reflect the lower federal income tax rate, partially offset by higher electric distribution rates in Maryland that became effective in October 2017 and 71% of Pepco’s retail kWh sales toJune 2018 and higher electric distribution rates in the District of Columbia customers and 60% of Pepco’s retail kWh sales to Maryland customers for year ended December 31, 2015.
Operating revenues 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 years ended December 31,became effective August 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Volume | $ | 16 |
| | $ | 15 |
|
Distribution rate increase | 66 |
| | 5 |
|
Regulatory required programs | (12 | ) | | 38 |
|
Transmission revenues | 9 |
| | (1 | ) |
Other | (15 | ) | | 13 |
|
Total increase | $ | 64 |
| | $ | 70 |
|
Volume.The increase in operatingAugust 2018. Distribution revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather,increased for the year ended December 31, 2017 compared to the same period in 2016, primarily reflects the impact of residential customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2016 compared to the same period in 2015 primarily reflects the impact of moderate economic and customer growth.
Distribution Rate Increase.The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2017 compared to the same period in 2016 was primarily due to the impact of the higher electric distribution rates charged to customers in Maryland that became effective in November 2016 and October 2017 and higher electric distribution rates charged to customers in the District of Columbia that became effective August 2017. The increase in distribution revenue for the year ended December 31, 2016 compared to the same period in 2015 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 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in Pepco's service territory. The changes in heating and cooling degree days in Pepco’s service territory for the years ended December 31, 2017 and December 31, 2016 compared to same periods in 2016 and 2015, respectively, and normal weather consisted of the following:
|
| | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 3,312 |
|
| 3,624 |
| | 3,869 |
| | (8.6 | )% | | (14.4 | )% |
Cooling Degree-Days | 1,767 |
|
| 1,936 |
| | 1,653 |
| | (8.7 | )% | | 6.9 | % |
| | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | | Normal | | 2016 vs. 2015 | | 2016 vs. Normal |
Heating Degree-Days | 3,624 |
| | 3,657 |
| | 3,887 |
| | (0.9 | )% | | (6.8 | )% |
Cooling Degree-Days | 1,936 |
| | 1,936 |
| | 1,626 |
| | — | % | | 19.1 | % |
Regulatory Required Programs.Programs This represents the change in Operatingrepresent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs.programs, DC PLUG and SOS administrative costs. The riders are designed to provide full and current cost recovery as well as a return.return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than incomeincome. Revenues from regulatory required programs increased for the year ended December 31, 2018 compared to the same period in Pepco's Consolidated Statements2017 primarily due to increases in the Maryland and District of OperationsColumbia surcharge rates and Comprehensive Income. Revenuesales due to higher volumes, as well as the DC PLUG surcharge which became effective in February 2018. Revenues from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period
in 2016 primarily due to lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January 2017. Revenue from regulatory required programs increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to higher demand-side management program surcharge revenue due to a rate increase effective February 2016. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.
Transmission RevenuesRevenues..Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments.the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses. Transmission2017.
Other revenue decreased for the year ended December 31, 2016 compared to the same period in 2015 due to lowerincludes rental revenue, revenue related to the MAPP abandonment recovery period that ended in March 2016, partially offset by higher rates effective June 1, 2016late payment charges, mutual assistance revenues and June 1, 2015 related to increases in transmission plant investment and operating expenses.
Other.The decrease inrecoveries of other operatingtaxes. Other revenue net of purchased power expensedecreased for the year ended December 31, 2017 compared to the same period in 2016 is primarily due to lower pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of lower sales that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction. The increase in other operating revenue net of purchased power expense
See Note 24 - Segment Information for the year ended December 31, 2016 comparedCombined Notes to Consolidated Financial Statements for the same periodpresentation of Pepco's revenue disaggregation.
The changes in 2015 is primarily due to higher pass-through revenue (which is substantially offset in Taxes other than income) primarily the result of higher sales that resulted in an increase in utility taxes that are collected by Pepco on behalfOperating and maintenance expense consisted of the jurisdiction.following:
Operating and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | 2017 vs. 2016 | | 2016 | | 2015 | | 2016 vs. 2015 |
Operating and maintenance expense - baseline | $ | 449 |
| | $ | 631 |
| | $ | (182 | ) | | $ | 631 |
| | $ | 427 |
| | $ | 204 |
|
Operating and maintenance expense - regulatory required programs(a) | 5 |
| | 11 |
| | (6 | ) | | 11 |
| | 12 |
| | (1 | ) |
Total operating and maintenance expense | $ | 454 |
| | $ | 642 |
| | $ | (188 | ) | | $ | 642 |
| | $ | 439 |
| | $ | 203 |
|
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | |
ARO update(a) | $ | 22 |
| | $ | — |
|
Merger costs(b) | 13 |
| | (132 | ) |
BSC and PHISCO costs(c) | 9 |
| | (24 | ) |
Uncollectible accounts expense | 2 |
| | (11 | ) |
Labor, other benefits, contracting and materials | (2 | ) | | 15 |
|
Write-off of construction work in progress(d) | — |
| | (14 | ) |
Remeasurement of AMI-related regulatory asset(e) | — |
| | (7 | ) |
Other | 4 |
| | (9 | ) |
| 48 |
|
| (182 | ) |
| | | |
Regulatory required programs | (1 | ) | | (6 | ) |
Total increase (decrease) | $ | 47 |
| | $ | (188 | ) |
__________
| |
(a) | Operating and maintenance expensesReflects an increase primarily related to asbestos identified at the Buzzard Point property. See Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for 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 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:additional information.
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 16 |
| | $ | 7 |
|
Storm-related costs | (1 | ) | | 6 |
|
Remeasurement of AMI-related regulatory asset(a) | (7 | ) | | 7 |
|
Deferral of billing system transition costs to regulatory asset | — |
| | (7 | ) |
Deferral of merger-related costs to regulatory asset | — |
| | (11 | ) |
Uncollectible accounts expense - provision | (11 | ) | | 8 |
|
BSC and PHISCO allocations(b) | (24 | ) | | 53 |
|
Merger commitments(c) | (132 | ) | | 126 |
|
Write-off of construction work in progress(d) | (14 | ) | | 13 |
|
Other | (9 | ) | | 2 |
|
| (182 | ) |
| 204 |
|
Regulatory required programs | | | |
Purchased power administrative costs | (6 | ) | | (1 | ) |
Total (decrease) increase | $ | (188 | ) | | $ | 203 |
|
__________
| |
(a) | Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016. |
| |
(b) | Primarily related to merger severance and compensation costs recognizedDecrease in 2016 |
| |
(c) | Primarily related2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of accumulated merger integration costs as regulatory assets in 2017. |
| |
(c) | Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016. |
| |
(d) | Primarily resulting from a review of capital projects during the fourth quarter of 2016. |
| |
(e) | Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016. |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Depreciation expense(a) | $ | 28 |
| | $ | 11 |
| $ | 14 |
| | $ | 28 |
|
Regulatory asset amortization(b) | 8 |
| | (11 | ) | 25 |
| | 8 |
|
Regulatory required programs (c) | (10 | ) | | 39 |
| 25 |
| | (10 | ) |
Total increase | $ | 26 |
| | $ | 39 |
| $ | 64 |
| | $ | 26 |
|
_________
| |
(a) | Depreciation expense increased primarily due to ongoing capital expenditures and higher depreciation rates in Maryland effective November 2016 and ongoing capital expenditures.2016. |
| |
(b) | Regulatory asset amortization increased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to higher amortization of AMI-relatedadditional regulatory assets partially offset by lower amortization of MAPP abandonment costs. Regulatory asset amortization decreased for the year ended December 31, 2016 comparedrelated to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs.rate case activity. |
| |
(c) | Regulatory required programs decreased forincreased as a result of higher amortization of the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses forDC PLUG regulatory required programs 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 and Operating and maintenance expense.asset. |
Taxes Other Than Income
other than income for the year ended December 31, 2018 compared to the same period in 2017 increased primarily due to an increase in utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues). Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to lower utility taxes that are collected and passed through by Pepco (which is substantially offset in Operating revenues), partially offset by higher property taxes. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher utility taxes that are collected and passed through by Pepco, partially offset by lower property taxes in Maryland.
Gain on Sales of Assets
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to higher gains recorded in 2016 at Pepco associated with the sale of land. Gain on sale of assetsland in May 2016.
Interest expense, net for the year ended December 31, 20162018 compared to the same period in 2015 decreased2017 increased primarily due to higher gains recorded in 2015 at Pepco associated with the sale of land held as non-utility property.
Interest Expense, Net
outstanding debt. Interest expense, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an uncertain tax position in 2016, partially offset by higher interest expense associated with the issuance of long term debt in May 2017. Interest expense, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to the recording of interest expense for an uncertain tax position in 2016, partially offset by an increase in capitalized AFUDCoutstanding debt.
Other, Net
Other, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the September 2016 reversal of contributions in aid of construction tax gross-
upgross-up reserves due to the determination that there is no legal obligation to refund customers per contract term. Other, net
Effective income tax rates for the years ended December 31, 2018, 2017, and 2016 were 5.8%, 33.9%, and 49.4%, respectively. The decrease in the effective income tax rate for the year ended December 31, 20162018 compared to the same period in 2015 increased2017 is primarily due to higher income from AFUDC equity.
Effective Income Tax Rate
Pepco's effectivethe lower federal income tax rates forrate as a result of the years ended December 31, 2017, 2016, and 2015 were 33.9%, 49.4%, and 35.3%, respectively.TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. In the first quarterrates
Results of 2017, Pepco decreased its liability for unrecognized tax benefits by $21 million resulting in a benefit to Income taxes and corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the $14 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $8 million associated with the Tax Cuts and Jobs Act in 2017.
As a result of the merger, Pepco recorded an after-tax charge of $31 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
Pepco Electric Operating Statistics and Revenue DetailOperations—DPL
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Residential | 7,831 |
| | 8,372 |
| | (6.5 | )% | | (2.5 | )% | | 8,452 |
| | (0.9 | )% | | (0.3 | )% |
Small commercial & industrial | 1,303 |
| | 1,459 |
| | (10.7 | )% | | (9.0 | )% | | 1,471 |
| | (0.8 | )% | | (0.6 | )% |
Large commercial & industrial | 14,988 |
| | 15,559 |
| | (3.7 | )% | | (2.5 | )% | | 15,351 |
| | 1.4 | % | | 1.6 | % |
Public authorities & electric railroads | 734 |
| | 724 |
| | 1.4 | % | | 1.4 | % | | 714 |
| | 1.4 | % | | 1.7 | % |
Total retail deliveries | 24,856 |
| | 26,114 |
| | (4.8 | )% | | (2.8 | )% | | 25,988 |
| | 0.5 | % | | 0.9 | % |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 792,211 |
| | 780,652 |
| | 767,392 |
|
Small commercial & industrial
| 53,489 |
| | 53,529 |
| | 53,838 |
|
Large commercial & industrial | 21,732 |
| | 21,391 |
| | 20,976 |
|
Public authorities & electric railroads | 144 |
| | 130 |
| | 129 |
|
Total | 867,576 |
| | 855,702 |
| | 842,335 |
|
|
| | | | | | | | | | | | | | | | | |
Electric Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Residential | $ | 956 |
| | $ | 1,000 |
| | (4.4 | )% | | $ | 970 |
| | 3.1 | % |
Small commercial & industrial | 147 |
| | 150 |
| | (2.0 | )% | | 153 |
| | (2.0 | )% |
Large commercial & industrial | 810 |
| | 803 |
| | 0.9 | % | | 777 |
| | 3.3 | % |
Public authorities & electric railroads | 33 |
| | 32 |
| | 3.1 | % | | 30 |
| | 6.7 | % |
Total retail | 1,946 |
| | 1,985 |
| | (2.0 | )% | | 1,930 |
| | 2.8 | % |
Other revenue(b) | 212 |
| | 201 |
| | 5.5 | % | | 199 |
| | 1.0 | % |
Total electric revenue(c) | $ | 2,158 |
| | $ | 2,186 |
| | (1.3 | )% | | $ | 2,129 |
| | 2.7 | % |
__________
| |
(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 $6 million for the year ended December 31, 2017 and $5 million for the years ended December 31, 2016 and 2015, respectively.
|
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 1,332 |
| | $ | 1,300 |
| | $ | 32 |
| | $ | 1,277 |
| | $ | 23 |
|
Purchased power and fuel expense | 561 |
| | 532 |
| | (29 | ) | | 583 |
| | 51 |
|
Revenues net of purchased power and fuel expense | 771 |
| | 768 |
| | 3 |
| | 694 |
| | 74 |
|
Other operating expenses | | | | | | | | |
|
|
Operating and maintenance | 344 |
| | 315 |
| | (29 | ) | | 441 |
| | 126 |
|
Depreciation and amortization | 182 |
| | 167 |
| | (15 | ) | | 157 |
| | (10 | ) |
Taxes other than income | 56 |
| | 57 |
| | 1 |
| | 55 |
| | (2 | ) |
Total other operating expenses | 582 |
| | 539 |
| | (43 | ) | | 653 |
| | 114 |
|
Gain on sales of assets | 1 |
| | — |
| | 1 |
| | 9 |
| | (9 | ) |
Operating income | 190 |
| | 229 |
| | (39 | ) | | 50 |
| | 179 |
|
Other income and (deductions) | | | | | | | | |
|
|
Interest expense, net | (58 | ) | | (51 | ) | | (7 | ) | | (50 | ) | | (1 | ) |
Other, net | 10 |
| | 14 |
| | (4 | ) | | 13 |
| | 1 |
|
Total other income and (deductions) | (48 | ) | | (37 | ) | | (11 | ) | | (37 | ) | | — |
|
Income before income taxes | 142 |
| | 192 |
| | (50 | ) | | 13 |
| | 179 |
|
Income taxes | 22 |
| | 71 |
| | 49 |
| | 22 |
| | (49 | ) |
Net income (loss) | $ | 120 |
| | $ | 121 |
| | $ | (1 | ) | | $ | (9 | ) | | $ | 130 |
|
ResultsYear Ended December 31, 2018 Compared to Year Ended December 31, 2017.Net income remained relatively consistent. The TCJA did not significantly impact Net income as the favorable tax impacts were predominately offset by lower revenues resulting from the pass back of Operationsthe tax savings through customer rates.—DPL
|
| | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance |
Operating revenues | $ | 1,300 |
| | $ | 1,277 |
| | $ | 23 |
| | $ | 1,302 |
| | $ | (25 | ) |
Purchased power and fuel expense | 532 |
| | 583 |
| | 51 |
| | 634 |
| | 51 |
|
Revenues net of purchased power and fuel expense(a) | 768 |
| | 694 |
| | 74 |
| | 668 |
| | 26 |
|
Other operating expenses | | | | | | | | |
|
|
Operating and maintenance | 315 |
| | 441 |
| | 126 |
| | 304 |
| | (137 | ) |
Depreciation and amortization | 167 |
| | 157 |
| | (10 | ) | | 148 |
| | (9 | ) |
Taxes other than income | 57 |
| | 55 |
| | (2 | ) | | 51 |
| | (4 | ) |
Total other operating expenses | 539 |
| | 653 |
| | 114 |
| | 503 |
| | (150 | ) |
Gain on sales of assets | — |
| | 9 |
| | (9 | ) | | — |
| | 9 |
|
Operating income | 229 |
| | 50 |
| | 179 |
| | 165 |
| | (115 | ) |
Other income and (deductions) | | | | | | | | |
|
|
Interest expense, net | (51 | ) | | (50 | ) | | (1 | ) | | (50 | ) | | — |
|
Other, net | 14 |
| | 13 |
| | 1 |
| | 10 |
| | 3 |
|
Total other income and (deductions) | (37 | ) | | (37 | ) | | — |
| | (40 | ) | | 3 |
|
Income before income taxes | 192 |
| | 13 |
| | 179 |
| | 125 |
| | (112 | ) |
Income taxes | 71 |
| | 22 |
| | (49 | ) | | 49 |
| | 27 |
|
Net income (loss) | $ | 121 |
| | $ | (9 | ) | | $ | 130 |
| | $ | 76 |
| | $ | (85 | ) |
__________
| |
(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 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)
Year Ended December 31, 2017Compared to Year Ended December 31, 2016.The increase in Net income was driven primarily by a decrease in Operating and maintenance expense increased $130 million primarily due to merger-related costs recognized in March 2016, and an increasehigher distribution base rates in Revenues net of purchased power and fuel expense as a result of the distribution rate increases approved by the DPSCDelaware that became effective July and December 2016 and ahigher distribution rate increase approved by the MDPSCbase rates in Maryland that became effective February 2017, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective February 2017. Income taxes expense incurred included unrecognized tax benefits of $16 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the $6 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $5 million associated with the Tax Cuts and Jobs Act in 2017.assets.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The decrease in Net income was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.
Operating RevenueRevenues Net of Purchased Power and Fuel Expense
Expense. There are certain drivers to Operating revenues include revenue from the distribution and supply of electricity and natural gas 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 regulatedare fully offset by FERC. Transmission rates are updated annually basedtheir impact on a FERC-approved formula methodology.
Electric and natural gas revenues and purchasedPurchased power and fuel expense, are also affected bysuch as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in participation in the Customer Choice Program. All DPL customersthese costs have minimal impact on RNF.
Customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers, respectively. The customers'suppliers. Customer choice of suppliers doesprograms do not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact Operating revenues related to supplied energy and natural gas service.electricity.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales, respectively) for the years ended December 31, 2017, 2016 and 2015,
The changes in RNF consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Electric | 52 | % | | 51 | % | | 51 | % |
Natural Gas | 33 | % | | 28 | % | | 31 | % |
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at December 31, 2017, 2016 and 2015 consisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 77,790 |
| | 14.9 | % | | 78,675 |
| | 15.2 | % | | 77,603 |
| | 15.1 | % |
Natural Gas | 154 |
| | 0.1 | % | | 156 |
| | 0.1 | % | | 159 |
| | 0.1 | % |
Retail deliveries purchased from competitive electric generation suppliers represented 54% of DPL’s retail kWh sales to Delaware customers and 48% of DPL retail kWh sales to Maryland customers for
the year ended December 31, 2017; 53% of DPL’s retail kWh sales to Delaware customers and 48% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2016; and 53% of DPL’s retail kWh sales to Delaware customers and 47% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2015.
Operating revenues 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 revenues 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 from on-system natural gas delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of off-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 for off-system sales.
The changes in DPL’s Operating revenues net of purchased power and fuel expense for the years ended December 31, 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:
| | | 2017 vs. 2016 | | 2016 vs. 2015 | 2018 vs. 2017 | | 2017 vs. 2016 |
| Increase (Decrease) | | Increase (Decrease) | Increase (Decrease) | | Increase (Decrease) |
| Electric | | Gas | | Total | | Electric | | Gas | | Total | Electric | | Gas | | Total | | Electric | | Gas | | Total |
Weather | $ | (7 | ) | | $ | (13 | ) | | $ | (20 | ) | | $ | — |
| | $ | — |
| | $ | — |
| $ | 11 |
| | $ | 8 |
| | $ | 19 |
| | $ | (7 | ) | | $ | (13 | ) | | $ | (20 | ) |
Volume | 2 |
| | 11 |
| | 13 |
| | 2 |
| | 2 |
| | 4 |
| 7 |
| | 2 |
| | 9 |
| | 2 |
| | 11 |
| | 13 |
|
Distribution rate increase | 65 |
| | 4 |
| | 69 |
| | 2 |
| | 1 |
| | 3 |
| |
Distribution revenue | | (20 | ) | | (6 | ) | | (26 | ) | | 65 |
| | 4 |
| | 69 |
|
Regulatory required programs | (3 | ) | | — |
| | (3 | ) | | 10 |
| | — |
| | 10 |
| (2 | ) | | (5 | ) | | (7 | ) | | (3 | ) | | — |
| | (3 | ) |
Transmission revenues | 10 |
| | — |
| | 10 |
| | 8 |
| | — |
| | 8 |
| 6 |
| | — |
| | 6 |
| | 10 |
| | — |
| | 10 |
|
Other | 6 |
| | (1 | ) | | 5 |
| | 1 |
| | — |
| | 1 |
| 1 |
| | 1 |
| | 2 |
| | 6 |
| | (1 | ) | | 5 |
|
Increase in revenue net of purchased power expense | $ | 73 |
|
| $ | 1 |
|
| $ | 74 |
|
| $ | 23 |
|
| $ | 3 |
|
| $ | 26 |
| |
Total increase | | $ | 3 |
|
| $ | — |
|
| $ | 3 |
|
| $ | 73 |
|
| $ | 1 |
|
| $ | 74 |
|
Revenue Decoupling. DPL’s results historically have been seasonal, generally producing higher revenueThe demand for electricity is affected by weather and incomecustomer usage. However, Operating revenues from electric distribution customers 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 thecustomer by customer class. While Operating revenues from electric 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 not impacted by abnormal weather or usage per customer, they are impacted by 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.customers.
Weather.The demand for electricity and natural gas in areas not subject to the BSADelaware is affected by weather conditions. With respect to the electric business, very warm weather in summer months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as "favorable weather conditions” because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. During the year ended December 31, 2018 compared to the same period in 2017, RNF related to weather was higher due to the impact of favorable weather conditions in DPL's Delaware service territory. During the year ended December 31, 2017 compared to the same period in 2016, operating revenues net of purchased power and fuel expensesRNF related to weather was lower due to the impact of unfavorable weather conditions in DPL's Delaware service territory. During the year ended December 31, 2016 compared to the same period in 2015, weather was not a significant impact.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the years ended December 31, 20172018 and December 31, 20162017 compared to same periods in 20162017 and 2015,2016, respectively, and normal weather consisted of the following:
| | Electric Service Territory | For the Years Ended December 31, | | | | % Change | |
Delaware Electric Service Territory | | For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal |
Heating Degree-Days | 4,077 |
| | 4,319 |
| | 4,519 |
| | (5.6 | )% | | (9.8 | )% | 4,713 |
| | 4,203 |
| | 4,624 |
| | 12.1 | % | | 1.9 | % |
Cooling Degree-Days | 1,300 |
| | 1,453 |
| | 1,210 |
| | (10.5 | )% | | 7.4 | % | 1,456 |
| | 1,265 |
| | 1,210 |
| | 15.1 | % | | 20.3 | % |
| | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | | | % Change | For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | | Normal | | 2016 vs. 2015 | | 2016 vs. Normal | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,319 |
| | 4,421 |
| | 4,572 |
| | (2.3 | )% | | (5.5 | )% | 4,203 |
| | 4,454 |
| | 4,664 |
| | (5.6 | )% | | (9.9 | )% |
Cooling Degree-Days | 1,453 |
| | 1,328 |
| | 1,188 |
| | 9.4 | % | | 22.3 | % | 1,265 |
| | 1,463 |
| | 1,193 |
| | (13.5 | )% | | 6.0 | % |
|
| | | | | | | | | | | | | | |
Natural Gas Service Territory | For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,203 |
| | 4,454 |
| | 4,739 |
| | (5.6 | )% | | (11.3 | )% |
| | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | | Normal | | 2016 vs. 2015 | | 2016 vs. Normal |
Heating Degree-Days | 4,454 |
| | 4,618 |
| | 4,754 |
| | (3.6 | )% | | (6.3 | )% |
|
| | | | | | | | | | | | | | |
Delaware Natural Gas Service Territory | For the Years Ended December 31, | | | | % Change |
Heating Degree-Days | 2018 | | 2017 | | Normal | | 2018 vs. 2017 | | 2018 vs. Normal |
Heating Degree-Days | 4,713 |
| | 4,203 |
| | 4,716 |
| | 12.1 | % | | (0.1 | )% |
| | | | | | | | | |
| For the Years Ended December 31, | | | | % Change |
Heating Degree-Days | 2017 | | 2016 | | Normal | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,203 |
| | 4,454 |
| | 4,739 |
| | (5.6 | )% | | (11.3 | )% |
Volume,. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, increased for the year ended December 31, 20172018 compared to the same period in 2016, primarily reflects the impact of customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects
of weather, for the year ended December 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and customer growth.
Distribution Rate Increase. The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2017 compared to the same period in 2016 was primarily due to the impact of the higher electric distribution and natural gas rates charged to Delaware customers that became effective in July and December 2016 and the impact of higher electric distribution rates charged to Maryland customers that became effective in February 2017. The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to Delaware customers that became effective in July 2016. See Note 3 — 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 Taxes other than incomeincreased average residential customer usage in DPL's Consolidated Statements of OperationsDelaware service territory and Comprehensive Income. Revenue from regulatory required programs decreasedoverall customer growth. Volume increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January 2017. Revenue from regulatory required programs increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to higher demand-side management program surcharge revenue due to a rate increase effective February 2016. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses. Transmission revenue increased for the year ended December 31, 2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.
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, and recoveriesimpact of other taxes.customer growth.
Operating and Maintenance Expense
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | | 2016 | | 2015 | |
Operating and maintenance expense - baseline | $ | 306 |
| | $ | 425 |
| | $ | (119 | ) | | $ | 425 |
| | $ | 289 |
| | $ | 136 |
|
Operating and maintenance expense - regulatory required programs(a) | 9 |
| | 16 |
| | (7 | ) | | 16 |
| | 15 |
| | 1 |
|
Total operating and maintenance expense | $ | 315 |
| | $ | 441 |
| | $ | (126 | ) | | $ | 441 |
| | $ | 304 |
| | $ | 137 |
|
__________
| |
(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 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 4 |
| | $ | 1 |
|
Storm-related costs | 4 |
| | 5 |
|
Deferral of billing system transition costs to regulatory asset | 2 |
| | (2 | ) |
Deferral of merger-related costs to regulatory asset | (6 | ) | | (4 | ) |
Uncollectible accounts expense - provision | (10 | ) | | 3 |
|
BSC and PHISCO allocations(a) | (15 | ) | | 34 |
|
Merger commitments(b) | (88 | ) | | 86 |
|
Write-off of construction work in progress(c) | (3 | ) | | 4 |
|
Other | (7 | ) | | 9 |
|
| (119 | ) |
| 136 |
|
Regulatory required programs | | | |
Purchased power administrative costs | (7 | ) | | 1 |
|
Total (decrease) increase | $ | (126 | ) | | $ | 137 |
|
_________
| |
(a) | Primarily related to merger severance and compensation costs recognized in 2016. |
| |
(b) | Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. |
| |
(c) | Primarily resulting from a review of capital projects during the fourth quarter of 2016. |
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Depreciation expense(a) | $ | 14 |
| | $ | 7 |
|
Regulatory asset amortization (b) | — |
| | (7 | ) |
Regulatory required programs(c) | (4 | ) | | 9 |
|
Total increase | $ | 10 |
| | $ | 9 |
|
_________
| |
(a) | Depreciation expense increased due to higher depreciation rates in Maryland effective February 2017 and due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to lower amortization of MAPP abandonment costs. |
| |
(c) | Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily due to an EmPower Maryland surcharge rate decrease effective February 2016 and increased for the year ended December 31, 2016 compared to the same period in 2015 due to an EmPower Maryland surcharge rate increase effective February 2015. Depreciation and amortization expenses for regulatory required programs are recoverable from customers on a full and current basis through approved regulated rates. A partially offsetting amount has been reflected in Operating revenues and Operating and maintenance expense. |
Taxes Other Than Income
Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016 remained relatively constant. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher property taxes in Maryland related to higher property assessments and rate increases.
Gain on Sales of Assets
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to gains recorded in 2016 at DPL associated with the sale of land held as non-utility property. Gain on sales of assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded in 2016 at DPL associated with the sale of land held as non-utility property.
Interest Expense, Net
Interest expense, net for the year ended December 31, 2017 compared to the same period in 2016 and for the year ended December 31, 2016 compared to the same period in 2015 remained relatively constant.
Other, Net
Other, net for the year ended December 31, 2017 compared to the same period in 2016 remained relatively constant. Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC equity.
Effective Income Tax Rate
DPL's effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were 37.0%, 169.2% and 39.2%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 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 corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the $6 million December 2017 impairment of certain transmission-related income tax regulatory assets and the one-time non-cash impacts of $5 million associated with the Tax Cuts and Jobs Act in 2017.
As a result of the merger, DPL recorded an after-tax charge of $23 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
DPL Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Residential | 5,010 |
| | 5,181 |
| | (3.3 | )% | | (0.3 | )% | | 5,337 |
| | (2.9 | )% | | (2.9 | )% |
Small commercial & industrial | 2,237 |
| | 2,290 |
| | (2.3 | )% | | (0.9 | )% | | 2,311 |
| | (0.9 | )% | | (1.3 | )% |
Large commercial & industrial | 4,585 |
| | 4,623 |
| | (0.8 | )% | | 0.3 | % | | 4,781 |
| | (3.3 | )% | | (3.9 | )% |
Public authorities & electric railroads | 44 |
| | 46 |
| | (4.3 | )% | | (8.3 | )% | | 45 |
| | 2.2 | % | | 6.7 | % |
Total retail deliveries | 11,876 |
| | 12,140 |
| | (2.2 | )% | | (0.2 | )% | | 12,474 |
| | (2.7 | )% | | (2.9 | )% |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 459,389 |
| | 456,181 |
| | 453,145 |
|
Small commercial & industrial | 60,697 |
| | 60,173 |
| | 59,714 |
|
Large commercial & industrial
| 1,400 |
| | 1,411 |
| | 1,410 |
|
Public authorities & electric railroads | 629 |
| | 643 |
| | 643 |
|
Total | 522,115 |
| | 518,408 |
| | 514,912 |
|
|
| | | | | | | | | | | | | | | | | |
Electric Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Residential | $ | 660 |
| | $ | 668 |
| | (1.2 | )% | | $ | 681 |
| | (1.9 | )% |
Small commercial & industrial | 185 |
| | 187 |
| | (1.1 | )% | | 192 |
| | (2.6 | )% |
Large commercial & industrial | 102 |
| | 98 |
| | 4.1 | % | | 101 |
| | (3.0 | )% |
Public authorities & electric railroads | 14 |
| | 13 |
| | 7.7 | % | | 12 |
| | 8.3 | % |
Total retail | 961 |
|
| 966 |
| | (0.5 | )% | | 986 |
| | (2.0 | )% |
Other revenue(b) | 178 |
| | 163 |
| | 9.2 | % | | 152 |
| | 7.2 | % |
Total electric revenue(c) | $ | 1,139 |
| | $ | 1,129 |
| | 0.9 | % | | $ | 1,138 |
| | (0.8 | )% |
|
| | | | | | | | | | | | | | | | | | | | |
Electric Retail Deliveries to Delaware Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change |
Retail Deliveries | | | | | | | | | | | | | |
Residential | 3,204 |
| | 2,967 |
| | 8.0 | % | | 1.8 | % | | 3,072 |
| | (3.4 | )% | | 0.9 | % |
Small commercial & industrial | 1,344 |
| | 1,317 |
| | 2.1 | % | | — | % | | 1,341 |
| | (1.8 | )% | | (0.2 | )% |
Large commercial & industrial | 3,636 |
| | 3,473 |
| | 4.7 | % | | 3.7 | % | | 3,476 |
| | (0.1 | )% | | 0.9 | % |
Public authorities & electric railroads | 33 |
| | 32 |
| | 3.1 | % | | 3.4 | % | | 35 |
| | (8.6 | )% | | (7.1 | )% |
Total electric retail deliveries(a) | 8,217 |
| | 7,789 |
| | 5.5 | % | | 2.3 | % | | 7,924 |
| | (1.7 | )% | | 0.7 | % |
__________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. 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 $8 million, $7 million and $6 million for the years ended December 31, 2017, 2016 and 2015, respectively. |
DPL Gas Operating Statistics and Revenue Detail |
| | | | | | | | |
| As of December 31, |
Number of Total Electric Customers (Maryland and Delaware) | 2018 | | 2017 | | 2016 |
Residential | 463,670 |
| | 459,389 |
| | 456,181 |
|
Small commercial & industrial | 61,381 |
| | 60,697 |
| | 60,173 |
|
Large commercial & industrial | 1,406 |
| | 1,400 |
| | 1,411 |
|
Public authorities & electric railroads | 621 |
| | 629 |
| | 643 |
|
Total | 527,078 |
| | 522,115 |
| | 518,408 |
|
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in mmcf) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather Normal % change | | 2015 | | % Change 2016 vs. 2015 | | Weather Normal % change |
Retail Deliveries | | | | | | | | | | | | | |
Residential | 13,107 |
| | 13,341 |
| | (1.8 | )% | | 5.2 | % | | 13,816 |
| | (3.4 | )% | | (0.4 | )% |
Transportation & other | 6,538 |
| | 6,201 |
| | 5.4 | % | | 6.9 | % | | 6,193 |
| | 0.1 | % | | 1.4 | % |
Total gas deliveries | 19,645 |
| | 19,542 |
| | 0.5 | % | | 5.7 | % | | 20,009 |
| | (2.3 | )% | | 0.1 | % |
|
| | | | | | | | | | | | | | | | | | | | |
Natural Gas Retail Deliveries to Delaware Customers (in mmcf) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather Normal % change | | 2016 | | % Change 2017 vs. 2016 | | Weather Normal % change |
Retail Deliveries | | | | | | | | | | | | | |
Residential | 8,633 |
| | 7,445 |
| | 16.0 | % | | 3.4 | % | | 7,765 |
| | (4.1 | )% | | 1.1 | % |
Small commercial & industrial | 4,134 |
| | 3,754 |
| | 10.1 | % | | (1.6 | )% | | 3,700 |
| | 1.5 | % | | 6.5 | % |
Large commercial & industrial | 1,952 |
| | 1,908 |
| | 2.3 | % | | 2.3 | % | | 1,875 |
| | 1.8 | % | | 1.7 | % |
Transportation | 6,831 |
| | 6,538 |
| | 4.5 | % | | 2.3 | % | | 6,202 |
| | 5.4 | % | | 6.3 | % |
Total natural gas deliveries(a) | 21,550 |
| | 19,645 |
| | 9.7 | % | | 2.0 | % | | 19,542 |
| | 0.5 | % | | 3.8 | % |
|
| | | | | | | | |
| As of December 31, |
Number of Gas Customers | 2017 | | 2016 | | 2015 |
Residential | 122,347 |
| | 120,951 |
| | 119,771 |
|
Commercial & industrial | 9,853 |
| | 9,801 |
| | 9,712 |
|
Transportation & other | 154 |
| | 156 |
| | 159 |
|
Total | 132,354 |
| | 130,908 |
| | 129,642 |
|
|
| | | | | | | | | | | | | | | | | |
Gas Revenue | 2017 | | 2016 | | % Change 2017 vs. 2016 | | 2015 | | % Change 2016 vs. 2015 |
Retail Sales(a) | | | | | | | | | |
Retail sales | $ | 136 |
| | $ | 127 |
| | 7.1 | % | | $ | 143 |
| | (11.2 | )% |
Transportation & other(b) | 25 |
| | 21 |
| | 19.0 | % | | 21 |
| | — | % |
Total gas revenues | $ | 161 |
| | $ | 148 |
| | 8.8 | % | | $ | 164 |
| | (9.8 | )% |
___________________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects |
|
| | | | | | | | |
| As of December 31, |
Number of Delaware Gas Customers | 2018 | | 2017 | | 2016 |
Residential | 124,183 |
| | 122,347 |
| | 120,951 |
|
Small commercial & industrial | 9,986 |
| | 9,833 |
| | 9,784 |
|
Large commercial & industrial | 18 |
| | 20 |
| | 17 |
|
Transportation | 156 |
| | 154 |
| | 156 |
|
Total | 134,343 |
| | 132,354 |
| | 130,908 |
|
Distribution Revenue decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to reduced electric distribution rates and gas distribution rates in Delaware that were put into effect in March 2018 which reflect the impact of the lower federal income tax rate. Distribution revenue increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to higher electric distribution and natural gas distribution base rates in Delaware that became effective in July and December 2016 and higher electric distribution base rates in Maryland that became effective in February 2017. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS administrative costs and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income.
Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue increased for the year ended December 31, 2018 compared to the same period in 2017 and for the year ended 2017 compared to the same period in 2016 due to higher rates effective June 2018 and June 2017.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
See Note 24 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | |
Merger costs(a) | $ | 7 |
| | $ | (94 | ) |
Energy efficiency merger commitments customer credits(b) | 5 |
| | — |
|
BSC and PHISCO costs(c) | 4 |
| | (15 | ) |
Labor, other benefits, contracting and materials | 4 |
| | 8 |
|
Write-off of construction work in progress(d) | 3 |
| | (3 | ) |
Uncollectible accounts expense | 1 |
| | (10 | ) |
Other | 6 |
| | (5 | ) |
| 30 |
|
| (119 | ) |
| | | |
Regulatory required programs | (1 | ) | | (7 | ) |
Total increase (decrease) | $ | 29 |
| | $ | (126 | ) |
_________
| |
(a) | Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to a deferral of natural gas.accumulated merger integration costs as regulatory assets in 2017. |
| |
(b) | TransportationRelated to EmPower Maryland energy efficiency customer credits. |
| |
(c) | Decrease in 2017 primarily related to merger severance and other revenue includes off-system natural gas sales and the short-term releasecompensation costs recognized in 2016. |
| |
(d) | Decrease in 2017 primarily related to a review of interstate pipeline transportation and storage capacity not needed to serve customers.capital projects in 2016. |
ResultsThe changes in Depreciation and amortization expense consisted of Operations—ACEthe following:
|
| | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance | | 2015 | | Favorable (unfavorable) 2016 vs. 2015 variance |
Operating revenues | $ | 1,186 |
| | $ | 1,257 |
| | $ | (71 | ) | | $ | 1,295 |
| | $ | (38 | ) |
Purchased power expense | 570 |
| | 651 |
| | 81 |
| | 708 |
| | 57 |
|
Revenues net of purchased power expense(a) | 616 |
| | 606 |
| | 10 |
| | 587 |
| | 19 |
|
Other operating expenses | | | | |
| | | |
|
Operating and maintenance | 307 |
| | 428 |
| | 121 |
| | 271 |
| | (157 | ) |
Depreciation and amortization | 146 |
| | 165 |
| | 19 |
| | 175 |
| | 10 |
|
Taxes other than income | 6 |
| | 7 |
| | 1 |
| | 7 |
| | — |
|
Total other operating expenses | 459 |
| | 600 |
| | 141 |
| | 453 |
| | (147 | ) |
Gain on sales of assets | — |
| | 1 |
| | (1 | ) | | — |
| | 1 |
|
Operating income | 157 |
| | 7 |
| | 150 |
| | 134 |
| | (127 | ) |
Other income and (deductions) | | | | |
| | | |
|
Interest expense, net | (61 | ) | | (62 | ) | | 1 |
| | (64 | ) | | 2 |
|
Other, net | 7 |
| | 9 |
| | (2 | ) | | 3 |
| | 6 |
|
Total other income and (deductions) | (54 | ) | | (53 | ) | | (1 | ) | | (61 | ) | | 8 |
|
Income (loss) before income taxes | 103 |
| | (46 | ) | | 149 |
| | 73 |
| | (119 | ) |
Income taxes | 26 |
| | (4 | ) | | (30 | ) | | 33 |
| | 37 |
|
Net income (loss) | $ | 77 |
| | $ | (42 | ) | | $ | 119 |
| | $ | 40 |
| | $ | (82 | ) |
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Depreciation expense(a) | $ | 6 |
| | $ | 14 |
|
Regulatory asset amortization (b) | 18 |
| | — |
|
Regulatory required programs(c) | (9 | ) | | (4 | ) |
Total increase | $ | 15 |
| | $ | 10 |
|
___________________
| |
(a) | ACE evaluates its operating performance using the measure of revenue net of purchased powerDepreciation 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 usedincreased due to evaluate its operational performance. ACE has included the analysis below as a complementongoing capital expenditures and higher depreciation rates in Maryland effective February 2017. |
| |
(b) | Regulatory asset amortization increased due to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense is not a presentation defined under GAAPadditional regulatory assets related to rate case activity. |
| |
(c) | Regulatory required programs decreased primarily due to an EmPower Maryland surcharge rate decrease effective January 2018 and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.2017. |
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the sale of land in July and December 2016.
Interest expense, net for the year ended December 31, 2018 compared to the same period in 2017 increased primarily due to higher outstanding debt.
Other, net for the year ended December 31, 2018 compared to the same period in 2017 decreased primarily due to lower income from AFUDC equity.
Effective income tax rates for the years ended December 31, 2018, 2017 and 2016 were 15.5%, 37.0% and 169.2%, respectively. The decrease in the effective income tax rate for the year ended December 31, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates
Results of Operations—ACE
|
| | | | | | | | | | | | | | | | | | | |
| 2018 | | 2017 | | Favorable (unfavorable) 2018 vs. 2017 variance | | 2016 | | Favorable (unfavorable) 2017 vs. 2016 variance |
Operating revenues | $ | 1,236 |
| | $ | 1,186 |
| | $ | 50 |
| | $ | 1,257 |
| | $ | (71 | ) |
Purchased power expense | 616 |
| | 570 |
| | (46 | ) | | 651 |
| | 81 |
|
Revenues net of purchased power expense | 620 |
| | 616 |
| | 4 |
| | 606 |
| | 10 |
|
Other operating expenses | | | | |
| | | |
|
Operating and maintenance | 330 |
| | 307 |
| | (23 | ) | | 428 |
| | 121 |
|
Depreciation and amortization | 136 |
| | 146 |
| | 10 |
| | 165 |
| | 19 |
|
Taxes other than income | 5 |
| | 6 |
| | 1 |
| | 7 |
| | 1 |
|
Total other operating expenses | 471 |
| | 459 |
| | (12 | ) | | 600 |
| | 141 |
|
Gain on sales of assets | — |
| | — |
| | — |
| | 1 |
| | (1 | ) |
Operating income | 149 |
| | 157 |
| | (8 | ) | | 7 |
| | 150 |
|
Other income and (deductions) | | | | |
| | | |
|
Interest expense, net | (64 | ) | | (61 | ) | | (3 | ) | | (62 | ) | | 1 |
|
Other, net | 2 |
| | 7 |
| | (5 | ) | | 9 |
| | (2 | ) |
Total other income and (deductions) | (62 | ) | | (54 | ) | | (8 | ) | | (53 | ) | | (1 | ) |
Income (loss) before income taxes | 87 |
| | 103 |
| | (16 | ) | | (46 | ) | | 149 |
|
Income taxes | 12 |
| | 26 |
| | 14 |
| | (4 | ) | | (30 | ) |
Net income (loss) | $ | 75 |
| | $ | 77 |
| | $ | (2 | ) | | $ | (42 | ) | | $ | 119 |
|
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017. Net Income (Loss)income remained relatively consistent. The TCJA did not significantly impact Net income as the favorable income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017Compared to Year Ended December 31, 2016.The increase in Net income was primarily due to a decrease in Operating and maintenance expenseIncome increased by $119 million primarily due to merger-related costs recognized in March 2016 and an increase in Revenues net of purchased power expense resulting from impact ofhigher electric distribution rate increases approved by the NJBPUbase rates effective August 2016 and October 2017 and an increase in transmission formula rate revenues, partially offset by lower customer usage. Income taxes expense incurred included unrecognized tax benefits of $22 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the December 2017 impairment of certain transmission-related income tax regulatory assets of $7 million and the one-time non-cash impacts of $2 million associated with the Tax Cuts and Jobs Act in 2017.million.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The decrease in Net income was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.
Revenues Net of Purchased Power Expense
Expense. There are certain drivers of 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 regulatedare fully offset by FERC. Transmission rates are updated annually basedtheir impact on a FERC-approved formula methodology.
Electric revenues and purchasedPurchased power expense, are also affected bysuch as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs from customers without mark-up. Therefore, fluctuations in participation in the Customer Choice Program. All ACE customersthese costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. The customer'sCustomer choice programs of supplier doesdo not impact the volume of deliveries or RNF, but affects revenue collected from customersimpact revenues related to supplied energy service.electricity.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31, 2017, 2016 and 2015,
The changes in RNF, consisted of the following:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Electric | 48 | % | | 47 | % | | 45 | % |
Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2017, 2016 and 2015 consisted of the following:
|
| | | | | | | | | | | | | | | | | |
| December 31, 2017 | | December 31, 2016 | | December 31, 2015 |
| Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers | | Number of customers | | % of total retail customers |
Electric | 86,155 |
| | 16 | % | | 94,562 |
| | 17 | % | | 78,299 |
| | 14 | % |
Operating revenues 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 wholesale markets for energy and capacity purchased under contracts 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 revenues net of purchased power expense for the years ended December 31, 2017 and 2016 compared to the same periods in 2016 and 2015, respectively, consisted of the following:
| | | Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 | Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Weather | $ | (3 | ) | | $ | (3 | ) | $ | 12 |
| | $ | (3 | ) |
Volume | (20 | ) | | 1 |
| 14 |
| | (20 | ) |
Distribution rate increase | 40 |
| | 14 |
| |
Distribution revenue | | 2 |
| | 40 |
|
Regulatory required programs | (24 | ) | | (14 | ) | (23 | ) | | (24 | ) |
Transmission revenues | 22 |
| | 23 |
| (4 | ) | | 22 |
|
Other | (5 | ) | | (2 | ) | 3 |
| | (5 | ) |
Increase in revenue net of purchased power expense | $ | 10 |
| | $ | 19 |
| |
Total increase | | $ | 4 |
| | $ | 10 |
|
Weather.The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. During the year ended December 31, 20172018 compared to the same period in 2016, operating revenues net of purchased power and fuel expense2017, RNF related to weather was lowerhigher due to the impact of unfavorable winterfavorable weather conditions in ACE's service territory. During the year ended December 31, 20162017 compared to the same period in 2015, operating revenues net of purchased power and fuel expense2016, RNF related to weather was lower due to the impact of unfavorable winter weather conditions in ACE's service territory.conditions.
For retail customers of ACE, distribution revenues are not decoupled for 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 a 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the years ended December 31, 20172018 and December 31, 20162017 compared to same periods in 20162017 and 2015,2016, respectively, and normal weather consisted of the following:
| | | For the Years Ended December 31, | | Normal | | % Change | For the Years Ended December 31, | | Normal | | % Change |
Heating and Cooling Degree-Days | 2017 | | 2016 | | 2017 vs. 2016 | | 2017 vs. Normal | 2018 | | 2017 | | 2018 vs. 2017 | | 2018 vs. Normal |
Heating Degree-Days | 4,206 |
| | 4,487 |
| | 4,713 |
| | (6.3 | )% | | (10.8 | )% | 4,523 |
| | 4,206 |
| | 4,666 |
| | 7.5 | % | | (3.1 | )% |
Cooling Degree-Days | 1,228 |
| | 1,303 |
| | 1,115 |
| | (5.8 | )% | | 10.1 | % | 1,535 |
| | 1,228 |
| | 1,135 |
| | 25.0 | % | | 35.2 | % |
| | | | | | | | | | | | | | | | | | |
| For the Years Ended December 31, | | Normal | | % Change | For the Years Ended December 31, | | Normal | | % Change |
Heating and Cooling Degree-Days | 2016 | | 2015 | | 2016 vs. 2015 | | 2016 vs. Normal | 2017 | | 2016 | | 2017 vs. 2016 | | 2017 vs. Normal |
Heating Degree-Days | 4,487 |
| | 4,671 |
| | 4,768 |
| | (3.9 | )% | | (5.9 | )% | 4,206 |
| | 4,487 |
| | 4,713 |
| | (6.3 | )% | | (10.8 | )% |
Cooling Degree-Days | 1,303 |
| | 1,259 |
| | 1,093 |
| | 3.5 | % | | 19.2 | % | 1,228 |
| | 1,303 |
| | 1,115 |
| | (5.8 | )% | | 10.1 | % |
Volume.Volume, The decrease in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, increased for the year ended December 31, 2018 compared to the same period in 2017, primarily due to higher average residential and commercial usage. Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2017 compared to the same period in 2016, primarily reflectsdue to lower average customer usage, partially offset by the impact of customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and customer growth, partially offset by lower average customer usage.
Distribution Rate Increase. The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2017 compared to the same period in 2016 was primarily due to the impact of the new electric distribution rates charged to customers that became effective in August 2016 and October 2017. The increase in electric operating revenues net of purchased power expense for the year ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to customers that became effective in August 2016. See Note 3 — 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 Taxes other than income in ACE's Consolidated Statements of Operations and Comprehensive Income. Revenue from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 due to a rate decrease effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Revenue from required regulatory programs decreased for the year ended December 31, 2016 compared to the same period in 2015 due to rate decreases effective October 2016 and October 2015 for the ACE Market Transition charge tax. Refer to the Operating and maintenance expense and Depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenues.Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered and other billing adjustments. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 1, 2017 and June 1, 2016 related to increases in transmission plant investment and operating expenses. Transmission revenue increased for the year ended December 31, 2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating expenses.
Operating and Maintenance Expense |
| | | | | | | | | | | | | | | | | | | | |
Electric Retail Deliveries to Customers (in GWhs) | 2018 | | 2017 | | % Change 2018 vs. 2017 | | Weather - Normal % Change | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Residential | 4,185 |
| | 3,853 |
| | 8.6 | % | | 4.0 | % | | 4,153 |
| | (7.2 | )% | | (6.2 | )% |
Small commercial & industrial | 1,361 |
| | 1,286 |
| | 5.8 | % | | 3.5 | % | | 1,455 |
| | (11.6 | )% | | (11.1 | )% |
Large commercial & industrial | 3,565 |
| | 3,399 |
| | 4.9 | % | | 3.7 | % | | 3,402 |
| | (0.1 | )% | | 0.4 | % |
Public authorities & electric railroads | 49 |
| | 47 |
| | 4.3 | % | | 4.5 | % | | 49 |
| | (4.1 | )% | | (4.1 | )% |
Total retail deliveries | 9,160 |
| | 8,585 |
| | 6.7 | % | | 3.8 | % | | 9,059 |
| | (5.2 | )% | | (4.5 | )% |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase (Decrease) | | Year Ended December 31, | | Increase (Decrease) |
| 2017 | | 2016 | | 2017 vs. 2016 | | 2016 | | 2015 | | 2016 vs. 2015 |
Operating and maintenance expense - baseline | $ | 303 |
| | $ | 424 |
| | $ | (121 | ) | | $ | 424 |
| | $ | 267 |
| | $ | 157 |
|
Operating and maintenance expense - regulatory required programs(a) | 4 |
| | 4 |
| | — |
| | 4 |
| | 4 |
| | — |
|
Total operating and maintenance expense | $ | 307 |
| | $ | 428 |
| | $ | (121 | ) | | $ | 428 |
| | $ | 271 |
| | $ | 157 |
|
__________
| |
(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 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 9 |
| | $ | 6 |
|
BSC and PHISCO allocations(a) | (11 | ) | | 26 |
|
Merger commitments(b) | (111 | ) | | 111 |
|
Deferral of merger-related costs to regulatory asset | (9 | ) | | — |
|
Other | 1 |
| | 14 |
|
Total (decrease) increase | $ | (121 | ) | | $ | 157 |
|
_________
| |
(a) | Primarily related to merger severance and compensation costs recognized in 2016. |
| |
(b) | Primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016.
|
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for 2017 compared to 2016 and 2016 compared to 2015 consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2017 vs. 2016 | | Increase (Decrease) 2016 vs. 2015 |
Depreciation expense(a) | $ | 6 |
| | $ | 6 |
|
Regulatory asset amortization | (2 | ) | | (4 | ) |
Required regulatory programs(b) | (24 | ) | | (12 | ) |
Other | 1 |
| | — |
|
Total decrease | $ | (19 | ) | | $ | (10 | ) |
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures. |
| |
(b) | Regulatory required programs decreased for the year ended December 31, 2017 compared to the same period in 2016 primarily as a result of lower revenue due to a rate decrease effective October 2016 for the ACE Transition Bond Charge and Market Transition Charge Tax. Required regulatory programs amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily as a result of lower revenue due to a rate decrease effective October 2015 for the ACE Market Transition charge tax. Depreciation and amortization expenses for regulatory required programs 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 and Operating and maintenance expense. |
Taxes Other Than Income
Taxes other than income for the year ended December 31, 2017 compared to the same period in 2016, remained constant. Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015, remained constant.
Interest Expense, Net
Interest expense, net remained relatively consistent for the year ended December 31, 2017, compared to the same period in 2016, and the year ended December 31, 2016, compared to the same period in 2015.
Gain on Sales of Assets
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to gains recorded in 2016 at ACE associated with the sale of property. Gain on sales of assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded in 2016 at ACE associated with the sale of property.
Other, Net
Other, net for the year ended December 31, 2017 compared to the same period in 2016 remained relatively constant. Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC equity.
Effective Income Tax Rate
ACE's effective income tax rates for the years ended December 31, 2017, 2016 and 2015 were 25.2%, 8.7%, and 45.2%, respectively. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates. 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 corresponding decrease to its effective tax rate. This decrease was offset by an increase in income taxes due to the December 2017
impairment of certain transmission-related income tax regulatory assets of $7 million and the one-time non-cash impacts of $2 million associated with the Tax Cuts and Jobs Act in 2017.
As a result of the merger, ACE recorded an after-tax charge of $22 million during the year ended December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
ACE Electric Operating Statistics and Revenue Detail
|
| | | | | | | | | | | | | | | | | | | | |
Retail Deliveries to Customers (in GWhs) | 2017 | | 2016 | | % Change 2017 vs. 2016 | | Weather - Normal % Change | | 2015 | | % Change 2016 vs. 2015 | | Weather - Normal % Change |
Retail Deliveries(a) | | | | | | | | | | | | | |
Residential | 3,853 |
| | 4,153 |
| | (7.2 | )% | | (6.2 | )% | | 4,322 |
| | (3.9 | )% | | (2.9 | )% |
Small commercial & industrial | 1,286 |
| | 1,455 |
| | (11.6 | )% | | (11.1 | )% | | 1,288 |
| | 13.0 | % | | 13.5 | % |
Large commercial & industrial | 3,399 |
| | 3,402 |
| | (0.1 | )% | | 0.4 | % | | 3,594 |
| | (5.3 | )% | | (5.2 | )% |
Public authorities & electric railroads | 47 |
| | 49 |
| | (4.1 | )% | | (4.1 | )% | | 45 |
| | 8.9 | % | | 8.9 | % |
Total retail deliveries | 8,585 |
| | 9,059 |
| | (5.2 | )% | | (4.5 | )% | | 9,249 |
| | (2.1 | )% | | (1.4 | )% |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2017 | | 2016 | | 2015 |
Residential | 487,168 |
| | 484,240 |
| | 482,000 |
|
Small commercial & industrial | 61,013 |
| | 61,008 |
| | 60,745 |
|
Large commercial & industrial | 3,684 |
| | 3,763 |
| | 3,871 |
|
Public authorities & electric railroads | 636 |
| | 610 |
| | 529 |
|
Total | 552,501 |
| | 549,621 |
| | 547,145 |
|
|
| | | | | | | | | | | | | | | | | |
| | | | | % Change 2017 vs. 2016 | | | | % Change 2016 vs. 2015 |
Electric Revenue | 2017 | | 2016 | | | 2015 | |
Retail Sales(a) | | | | | | | | | |
Residential | $ | 619 |
| | $ | 664 |
| | (6.8 | )% | | $ | 690 |
| | (3.8 | )% |
Small commercial & industrial | 166 |
| | 183 |
| | (9.3 | )% | | 175 |
| | 4.6 | % |
Large commercial & industrial | 189 |
| | 201 |
| | (6.0 | )% | | 213 |
| | (5.6 | )% |
Public authorities & electric railroads | 13 |
| | 13 |
| | — | % | | 12 |
| | 8.3 | % |
Total retail | 987 |
| | 1,061 |
| | (7.0 | )% | | 1,090 |
| | (2.7 | )% |
Other revenue(b) | 199 |
| | 196 |
| | 1.5 | % | | 205 |
| | (4.4 | )% |
Total electric revenue(c) | $ | 1,186 |
| | $ | 1,257 |
| | (5.6 | )% | | $ | 1,295 |
| | (2.9 | )% |
|
| | | | | | | | |
| As of December 31, |
Number of Electric Customers | 2018 | | 2017 | | 2016 |
Residential | 490,975 |
| | 487,168 |
| | 484,240 |
|
Small commercial & industrial | 61,386 |
| | 61,013 |
| | 61,008 |
|
Large commercial & industrial | 3,515 |
| | 3,684 |
| | 3,763 |
|
Public authorities & electric railroads | 656 |
| | 636 |
| | 610 |
|
Total | 556,532 |
| | 552,501 |
| | 549,621 |
|
__________
| |
(a) | Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and transmission. |
(b) Distribution Revenue increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to higher electric distribution base rates that became effective in November 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate. Distribution revenue increased for the year ended December 31, 2017 compared to the same period in 2016, primarily due to higher electric distribution base rates that became effective in August 2016 and October 2017. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds and BGS administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Operating and maintenance expense, Depreciation and amortization expense and Taxes other than income. Revenues from regulatory programs decreased for the year ended December 31, 2018 compared to the same period in 2017, and for the year ended 2017 compared to the same period in 2016 due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds.
Transmission Revenues. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs, capital investments being recovered, the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the impact of the lower federal income tax rate. Transmission revenue increased for the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 2017 and June 2016 related to increases in transmission plant investment and operating expenses.
Other revenue includes transmissionrental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.
See Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Baseline | | | |
Labor, other benefits, contracting and materials | $ | 17 |
| | $ | 9 |
|
BSC and PHISCO costs(a) | 10 |
| | (11 | ) |
Merger costs(b) | 7 |
| | (120 | ) |
Uncollectible accounts expense(c) | (8 | ) | | — |
|
Other | (2 | ) | | 1 |
|
| 24 |
| | (121 | ) |
| | | |
Regulatory required programs | (1 | ) | | — |
|
Total increase (decrease) | $ | 23 |
| | $ | (121 | ) |
_________
| |
(a) | Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016. |
| |
(b) | Decrease in 2017 primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily related to a deferral of accumulated merger integration costs as regulatory assets in 2017. |
| |
(c) | ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented. |
The changes in Depreciation and amortizationexpense consisted of the following:
|
| | | | | | | |
| Increase (Decrease) 2018 vs. 2017 | | Increase (Decrease) 2017 vs. 2016 |
Depreciation expense(a) | $ | 5 |
| | $ | 6 |
|
Regulatory asset amortization(b) | 5 |
| | (2 | ) |
Required regulatory programs(c) | (20 | ) | | (24 | ) |
Other | — |
| | 1 |
|
Total decrease | $ | (10 | ) | | $ | (19 | ) |
_________
| |
(a) | Depreciation expense increased due to ongoing capital expenditures. |
| |
(b) | Regulatory asset amortization increased due to additional regulatory assets related to rate case activity. |
| |
(c) | Regulatory required programs decreased due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds. |
Other, net for the year ended December 31, 2018 compared to the same period in 2017 decreased primarily due to lower income from PJMAFUDC equity.
Effective income tax rates were 13.8%, 25.2%, and wholesale electric revenues.
(c) Includes operating revenues from affiliates totaling $2 million, $3 million and $4 million8.7% for the years ended December 31, 2018, 2017 and 2016, and 2015, respectively. The decrease for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
Liquidity and Capital Resources
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through December 31, 2017.2018. Exelon prior year activity is unadjusted for the effects of the
PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL and ACE the activity presented below include its activity for the years ended December 31, 2018, 2017 2016 and 2015.2016. All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations 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 $480$545 million in bilateral facilities with banks which have various expirations between JanuaryOctober 2019 and December 2019.April 2021 and $159 in credit facilities for project finance. The Registrants utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for further discussion.additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, 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 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further discussionadditional information 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 15 - Asset Retirement Obligations of 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 investmentsfunds could appreciate in value. A shortfall could require Exelon to postthat Generation address the shortfall by, among other things, obtaining a parental guaranteesguarantee for Generation’s share of the obligations.funding assurance. However, the amount of any required guarantees or other assurance will ultimately depend on the decommissioning approach, adopted at each site, the associated level of costs, and the decommissioning trustNDT 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 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements, Generation filed its biennialannual decommissioning funding status report with the NRC on March 31, 201728, 2018 for shutdown reactors and demonstrated adequate funding assurance for all nuclear units currently operating.reactors within five years of shutdown. As of December 31, 2017,2018, across the four alternative decommissioning approaches available, Generation estimates a parental guarantee of up to $90 million from Exelon could be required for TMI, dependent upon the ultimate decommissioning approach selected. For Oyster Creek, none of the alternative decommissioning approaches available, Exelon would require Exelonnot be required to post a parental guarantee.guarantee for TMI or Oyster Creek. In the event PSEG decides to early retire Salem, Generation estimates a parental guarantee of up to $45$30 million from Exelon could be required for Salem, dependent upon the ultimate decommissioning approach selected.selected.
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). 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 EnergyDOE reimbursement agreements or future litigation, across the four alternative decommissioning approaches available, if TMI or Oyster Creek were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $225 million and $200$125 million net of taxes, respectively, dependent upon the ultimate decommissioning approach selected. In the event PSEG decides to early retire Salem and Salem were to fail to obtain the exemption, Generation estimates it could incur spent fuel management and site restoration costs over the next ten years of up to $80$90 million net of taxes. On October 19, 2018, the NRC granted Generation's exemption request to use the Oyster Creek NDT funds for non-radiological decommissioning costs.
On July 31, 2018, Generation entered into an agreement for the sale of Oyster Creek which is expected to occur in the second half of 2019. See Note 5 - Mergers, Acquisitions and Dispositions for additional information on the sale of Oyster Creek to Holtec.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of December 31, 2017. See Note 2120 — Earnings Per Share of the Combined Notes to Consolidated Financial Statements for furtheradditional information on the issuance of common stock.
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, 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 3Note 4 — Regulatory Matters and 23Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further discussionadditional information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | | 2017 | | 2016 | | 2017 vs. 2016 Variance | | 2015 | | 2016 vs. 2015 Variance | 2018 | | 2017 | | 2018 vs. 2017 Variance | | 2016 | | 2017 vs. 2016 Variance |
Net income | $ | 3,849 |
| | $ | 1,204 |
| | $ | 2,645 |
| | 2,250 |
| | $ | (1,046 | ) | $ | 2,084 |
| | $ | 3,876 |
| | $ | (1,792 | ) | | $ | 1,196 |
| | $ | 2,680 |
|
Add (subtract): | | | | | | | | | | | | | | | | | | |
Non-cash operating activities(a) | 5,446 |
| | 7,722 |
| | (2,276 | ) | | 5,630 |
| | 2,092 |
| 7,580 |
| | 5,445 |
| | 2,135 |
| | 7,714 |
| | (2,269 | ) |
Pension and non-pension postretirement benefit contributions | (405 | ) | | (397 | ) | | (8 | ) | | (502 | ) | | 105 |
| (383 | ) | | (405 | ) | | 22 |
| | (397 | ) | | (8 | ) |
Income taxes | 299 |
| | (674 | ) | | 973 |
| | 97 |
| | (771 | ) | 340 |
| | 299 |
| | 41 |
| | 576 |
| | (277 | ) |
Changes in working capital and other noncurrent assets and liabilities(b) | (1,579 | ) | | (275 | ) | | (1,304 | ) | | (264 | ) | | (11 | ) | (1,016 | ) | | (1,605 | ) | | 589 |
| | (243 | ) | | (1,362 | ) |
Option premiums received (paid), net | 28 |
| | (66 | ) | | 94 |
| | 58 |
| — |
| (124 | ) | (43 | ) | | 28 |
| | (71 | ) | | (66 | ) | — |
| 94 |
|
Collateral received (posted), net | (158 | ) | | 931 |
| | (1,089 | ) | | 347 |
| | 584 |
| 82 |
| | (158 | ) | | 240 |
| | 931 |
| | (1,089 | ) |
Deposit with IRS | | — |
| | — |
| | — |
| | (1,250 | ) | | 1,250 |
|
Net cash flows provided by operations | $ | 7,480 |
| | $ | 8,445 |
| | $ | (965 | ) | | $ | 7,616 |
| | $ | 829 |
| $ | 8,644 |
| | $ | 7,480 |
| | $ | 1,164 |
| | $ | 8,461 |
| | $ | (981 | ) |
__________
| |
(a) | Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts, pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items, stock compensation expense, impairment of long-lived assets, gain on sale of assets and businesses and other non-cash charges. See Note 2423 —Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for further detailadditional information on non-cash operating activity. |
| |
(b) | Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt. |
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy of contributing the greater of (1) $300 million (updated for the inclusion of PHI) until all the qualified plans are fully funded on an ABO basis, and (2) the minimum amounts under ERISA to meet minimum contribution requirements and/or avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike
the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2018:2019:
| | | Qualified Pension Plans | | Non-Qualified Pension Plans | | Other Postretirement Benefits | Qualified Pension Plans | | Non-Qualified Pension Plans | | Other Postretirement Benefits |
Exelon | $ | 301 |
| | $ | 30 |
| | $ | 42 |
| $ | 301 |
| | $ | 25 |
| | $ | 44 |
|
Generation | 119 |
| | 11 |
| | 13 |
| 135 |
| | 7 |
| | 13 |
|
ComEd | 38 |
| | 2 |
| | 3 |
| 65 |
| | 1 |
| | 2 |
|
PECO | 17 |
| | 1 |
| | — |
| 25 |
| | 1 |
| | — |
|
BGE | 41 |
| | 1 |
| | 16 |
| 34 |
| | 1 |
| | 15 |
|
BSC | 36 |
| | 7 |
| | 1 |
| 41 |
| | 7 |
| | 2 |
|
PHI | 50 |
| | 8 |
| | 9 |
| 1 |
| | 8 |
| | 12 |
|
Pepco | 4 |
| | 2 |
| | 8 |
| — |
| | 2 |
| | 10 |
|
DPL | — |
| | 1 |
| | — |
| — |
| | 1 |
| | — |
|
ACE | 6 |
| | — |
| | — |
| — |
| | — |
| | 1 |
|
PHISCO | 40 |
| | 5 |
| | 1 |
| 1 |
| | 5 |
| | 1 |
|
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding strategy.
On October 3, 2017, the US Department of Treasury and IRS released final regulations updating the mortality tables to be used for defined benefit pension plan funding, as well as the valuation of lump sum and other accelerated distribution options, effective for plan years beginning in 2018. The new mortality tables reflect improved projected life expectancy as compared to the existing table, which is generally expected to increase minimum pension funding requirements, Pension Benefit Guaranty Corporation premiums and the value of lump sum distributions. The IRS permits plan sponsors the option of delaying use of the new mortality tables for determining minimum funding requirements until 2019, which Exelon intends to utilize. The one-year delay does not apply for use of the mortality tables to determine the present value of lump sum distributions. The estimated impact of the new mortality tables along with other current assumptions and market information are reflected in the estimated future pension contributions in the “Contractual Obligations” section below.
The EMA requires CENG to fund the obligation related to pre-transfer service of employees, including the underfunded balance of the pension and other postretirement welfare benefit plans
measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG. However, in the event that EDF exercises its rights under the Put Option, all payments not made as of the put closing date shall accelerate to be paid immediately prior to such closing date. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the investment in CENG.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
Pursuant to the TCJA, beginning in 2018 Generation is expected to have higher operating cash flows in the range of approximately $1.2 billion to $1.6 billion for the period from 2018 to 2021, reflecting the reduction in the corporate federal income tax rate and full expensing of capital investments.
The TCJA is generally expected to result in lower operating cash flows for the Utility Registrants as a result of the elimination of bonus depreciation and lower customer rates. Increased operating cash flows for the Utility Registrants from lower corporate federal income tax rates is expected to be more than offset over time by lower customer rates resulting from lower income tax expense recoveries and the settlement of deferred income tax net regulatory liabilities established pursuant to the TCJA. The amount and timing of settlement of the net regulatory liabilities will be determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
| Exelon | | ComEd | | PECO(a) | | BGE | | PHI | | PEPCO | | DPL | | ACE |
Subject to IRS Normalization Rules | $ | 3,040 |
| | $ | 1,400 |
| | $ | 533 |
| | $ | 459 |
| | $ | 648 |
| | $ | 299 |
| | $ | 195 |
| | $ | 153 |
|
Subject to Rate Regulator Determination | 1,694 |
| | 573 |
| | 43 |
| | 324 |
| | 754 |
| | 391 |
| | 194 |
| | 170 |
|
Net Regulatory Liabilities | $ | 4,734 |
| | $ | 1,973 |
| | $ | 576 |
| | $ | 783 |
| | $ | 1,402 |
| | $ | 690 |
| | $ | 389 |
| | $ | 323 |
|
__________
| |
(a) | Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remains in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information. |
Net regulatory liability amounts subject to normalization rules generally may not be passed back to customers any faster than over the remaining useful lives of the underlying assets giving rise to the associated deferred income taxes. Such deferred income taxes generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the remaining amounts, rate regulators could require the passing back of amounts to customers over shorter time frames, which could materially decrease operating cash outflows at each of the Utility Registrants in the near term.
The Utility Registrants expect to fund any such required incremental operating cash outflows using a combination of third party debt financings and equity funding from Exelon in combinations generally consistent with existing capitalization ratio structures. To fund any additional equity contributions to the Utility Registrants, Exelon would have available to it its typical sources, including, but not limited to, the increased operating cash flows at Generation
referenced above, which over time are expected to exceed the incremental equity needs at the Utility Registrants.
The Utility Registrants continue to work with their state regulatory commissions to determine the amount and timing of the passing back of TCJA income tax savings benefits to customers; with filings either made, or expected to be made, at Pepco, DPL and ACE, and approved filings at ComEd and BGE. The amounts being passed back or proposed to be passed back to customers reflect the benefit of lower income tax expense beginning January 1, 2018 (Feb. 1, 2018 for DPL Delaware), and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. To date, neither the PAPUC nor FERC has yet issued guidance on how and when to reflect the impacts of the TCJA in customer rates. Refer to Note 3 - Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information on their filings.
In general, most states use federal taxable income as the starting point for computing state corporate income tax. Now that the TCJA has been enacted, state governments are beginning to analyze the impact of the TCJA on their state revenues. Exelon is uncertain regarding what the state governments will do, and there is a possibility that state corporate income taxes could change due to the enactment of the TCJA. In 2018, Exelon will be closely monitoring the states’ responses to the TCJA as these could have an impact on Exelon’s future cash flows.
See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Information for further information on the amounts of the net regulatory liabilities subject to determinations by rate regulators.
Exelon appealed the Tax Court’s like-kind exchange decision in the third quarter of 2017. In the fourth quarter of 2017, the IRS assessed the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd. While Exelon will receive a tax benefit of approximately $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 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 on ComEd’s equity from the like-kind exchange position.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. As a result of the IRS’s assessment of the tax, penalties and interest in the fourth quarter of 2017, the deposit is no longer available to Exelon and thus was reclassified from a current asset and is now reflected as an offset to the related liabilities for the tax, penalties, and interest that are included on Exelon’s balance sheet as current liabilities. The remaining amount due of approximately $20 million was paid in the fourth quarter of 2017. In the third quarter of 2017, the $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the like-kind exchange tax position.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax, property taxes and other taxes or the imposition, extension or permanence of temporary tax increases. On July 6, 2017, Illinois enacted Senate Bill 9, which permanently increased Illinois’ total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The rate increase is not expected to have a material ongoing
impact to Exelon’s, Generation’s or ComEd’s future cash taxes. See Note 14 - Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the Illinois tax rate change.
Cash flows provided by operationsoperating activities for the year ended December 31, 2018, 2017 2016 and 20152016 by Registrant were as follows:
| | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Exelon | $ | 7,480 |
| | $ | 8,445 |
| | $ | 7,616 |
| $ | 8,644 |
| | $ | 7,480 |
| | $ | 8,461 |
|
Generation | 3,299 |
| | 4,444 |
| | 4,199 |
| 3,861 |
| | 3,299 |
| | 4,442 |
|
ComEd | 1,527 |
| | 2,505 |
| | 1,896 |
| 1,749 |
| | 1,527 |
| | 2,505 |
|
PECO | 755 |
| | 829 |
| | 770 |
| 739 |
| | 755 |
| | 829 |
|
BGE | 821 |
| | 945 |
| | 782 |
| 789 |
| | 821 |
| | 945 |
|
Pepco | 407 |
| | 651 |
| | 373 |
| 474 |
| | 407 |
| | 651 |
|
DPL | 321 |
| | 310 |
| | 266 |
| 352 |
| | 321 |
| | 310 |
|
ACE | 206 |
| | 385 |
| | 256 |
| 228 |
| | 206 |
| | 385 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 950 |
| | $ | 888 |
| | | $ | 264 |
| | $ | 939 |
|
|
| | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 1,132 |
| $ | 950 |
| | $ | 888 |
| | | $ | 264 |
|
Changes in Registrants' cash flows from operations for 2018, 2017, and 2016 were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below.business. In addition, significant operating cash flow impacts for the Registrants for 2018, 2017 2016 and 20152016 were as follows:
Generation
Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC
markets. During 2018, 2017 2016 and 2015,2016, Generation had net collections/collections (payments) of counterparty cash collateral of $64 million, $(129) million $923 million and $407$923 million, respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.
During 2018, 2017 2016 and 2015,2016, Generation had net collections/(payments) collections of approximately $(43) million, $28 million $(66) million and $58$(66) million, respectively, related to purchases and sales of options. The level of option activity in a given year may vary due to several factors, including changes in market conditions as well as changes in hedging strategy.
ComEd
During 2017, 2016, and 2015 ComEd (posted)/received approximately $(27 million), $7 million, and $(31 million) of cash collateral with/from PJM, respectively. ComEd’s collateral posted with PJM has increased from 2017 to 2016, primarily due to an increase in ComEd’s RPM credit requirements and peak market activity with PJM. The collateral posted with PJM decreased from 2016 to 2015 due to lower PJM billings.
For further discussionadditional information regarding changes in non-cash operating activities, please refer tosee Note 2423 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Investing Activities
Cash flows used in investing activities for the year ended December 31, 2018, 2017 2016 and 20152016 by Registrant were as follows:
| | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Exelon | $ | (7,934 | ) | | $ | (15,503 | ) | | $ | (7,822 | ) | $ | (7,834 | ) | | $ | (7,971 | ) | | $ | (15,450 | ) |
Generation (a) | (2,592 | ) | | (3,851 | ) | | (4,069 | ) | (2,531 | ) | | (2,662 | ) | | (3,816 | ) |
ComEd | (2,296 | ) | | (2,685 | ) | | (2,362 | ) | (2,097 | ) | | (2,230 | ) | | (2,685 | ) |
PECO | (597 | ) | | (798 | ) | | (588 | ) | (840 | ) | | (597 | ) | | (797 | ) |
BGE | (849 | ) | | (910 | ) | | (675 | ) | (950 | ) | | (875 | ) | | (910 | ) |
Pepco | (630 | ) | | (647 | ) | | (477 | ) | (654 | ) | | (628 | ) | | (616 | ) |
DPL | (429 | ) | | (336 | ) | | (345 | ) | (362 | ) | | (429 | ) | | (336 | ) |
ACE | (310 | ) | | (309 | ) | | (306 | ) | (334 | ) | | (313 | ) | | (307 | ) |
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | (1,396 | ) | | $ | (1,030 | ) | | | $ | (343 | ) | | $ | (1,161 | ) |
|
| | | | | | | | | | | | | | | | |
| Successor | | | | Predecessor |
| 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
PHI | $ | (1,371 | ) | $ | (1,397 | ) | | $ | (993 | ) | | | | $ | (346 | ) |
Significant investing cash flow impacts for the Registrants for 2018, 2017 2016 and 20152016 were as follows:
Exelon
During 2017, Exelon had additional expenditures of $23 million and $178 million relating to the ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively. During 2016, Exelon had expenditures of $6.6 billion $235 million, and $58 million relatingrelated to the acquisitions of PHI ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.
During 2017, Exelon had proceeds of $219 million from sales of long-lived assets.merger.
During 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.
Exelon and Generation
During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the Handley generating station, respectively.
During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.
During 2017, Exelon and Generation had additional expenditures of $23 million and $178 million relating to the ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively. During 2016, Generation had expenditures of $235 million, and $58 million relatingrelated to the acquisitions of ConEdison Solutions and the acquisitions of the FitzPatrick nuclear generating station, respectively.
During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets.assets, primarily related to the sale back of turbine equipment.
During 2016, Exelon and Generation had expenditures of $235 million and $58 million related to the acquisitions of ConEdison Solutions and the FitzPatrick nuclear generating station, respectively.
Capital Expenditure Spending
Generation
Generation has entered into several agreements to acquire equity interests in privately held development stage entities which develop energy-related technology. The agreements contain a series of scheduled investment commitments, including in-kind services contributions. There are anticipated expenditures to fund anticipated planned capital and operating needs of the associated companies.
Capital expenditures by Registrant for the year ended December 31,2018, 2017 2016 and 20152016 and projected amounts for 20182019 are as follows:
| | | Projected 2018 (a) | | 2017 | | 2016 | | 2015 | Projected 2019 (a) | | 2018 | | 2017 | | 2016 |
Exelon(b) | $ | 7,825 |
| | $ | 7,584 |
| | $ | 8,553 |
| | $ | 7,624 |
| $ | 7,325 |
| | $ | 7,594 |
| | $ | 7,584 |
| | $ | 8,553 |
|
Generation | 2,100 |
| | 2,259 |
| | 3,078 |
| | 3,841 |
| 1,950 |
| | 2,242 |
| | 2,259 |
| | 3,078 |
|
ComEd(c) | 2,125 |
| | 2,250 |
| | 2,734 |
| | 2,398 |
| 1,875 |
| | 2,126 |
| | 2,250 |
| | 2,734 |
|
PECO | 800 |
| | 732 |
| | 686 |
| | 601 |
| 975 |
| | 849 |
| | 732 |
| | 686 |
|
BGE | 1,000 |
| | 882 |
| | 934 |
| | 719 |
| 1,100 |
| | 959 |
| | 882 |
| | 934 |
|
Pepco | 725 |
| | 628 |
| | 586 |
| | 544 |
| 725 |
| | 656 |
| | 628 |
| | 586 |
|
DPL | 400 |
| | 428 |
| | 349 |
| | 352 |
| 350 |
| | 364 |
| | 428 |
| | 349 |
|
ACE | 375 |
| | 312 |
| | 311 |
| | 300 |
| 300 |
| | 335 |
| | 312 |
| | 311 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | Predecessor |
| Projected 2018 (a) | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI(d) | $ | 1,500 |
| | $ | 1,396 |
| | $ | 1,008 |
| | | $ | 273 |
| | $ | 1,230 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| | | Successor | | | | Predecessor |
| Projected 2019 (a) | | 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
PHI(c) | $ | 1,375 |
| | $ | 1,375 |
| $ | 1,396 |
| | $ | 1,008 |
| | | | $ | 273 |
|
__________
| |
(a) | Total projected capital expenditures do not include adjustments for non-cash activity. Amounts are rounded to the nearest $25 million. |
| |
(b) | Includes corporate operations, BSC and PHISCO rounded to the nearest $25 million.PHISCO. |
| |
(c) | The capital expenditures and 2018 projections include $86 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately $2.6 billion over a ten-year period to modernize and storm-harden its distribution system and to implement smart grid technology. |
| |
(d) | Includes PHISCO rounded to the nearest $25 million.PHISCO. |
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 40%43% and 10%8% of the projected 20182019 capital expenditures at Generation are for the acquisition of nuclear fuel, and the construction of new natural gas plants and solar facilities, respectively, with the remaining amounts reflecting investment in renewable energy and additions and upgrades to existing facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that theyit will fund capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Projected 20182019 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants' construction commitments under PJM’s RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO and BGE submitted their final bi-annual reports to NERC in January 2014. ComEd PECO and BGEPECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments. Specific projects and
expenditures are identified as the assessments are completed. ComEd’s and PECO’s and BGE’s forecasted 20182019 capital expenditures above reflect capital spending for remediation to be completed through 2019. Pepco,BGE, DPL and ACE haveare complete with their assessments and Pepco has substantially completed their assessmentsits assessment and thus do not expect significant capital expenditures related to this guidance in 2018.2019.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional capital contributions from parent.
Cash Flows from Financing Activities
Cash flows (used in) provided by (used in) financing activities for the year ended December 31, 2018, 2017 2016 and 20152016 by Registrant were as follows:
|
| | | | | | | | | | | |
| 2017 | | 2016 | | 2015 |
Exelon | $ | 717 |
| | $ | 1,191 |
| | $ | 4,830 |
|
Generation | (581 | ) | | (734 | ) | | (479 | ) |
ComEd | 789 |
| | 169 |
| | 467 |
|
PECO | 50 |
| | (263 | ) | | 83 |
|
BGE | 22 |
| | (21 | ) | | (162 | ) |
Pepco | 219 |
| | — |
| | 103 |
|
DPL | 64 |
| | 67 |
| | 80 |
|
ACE | 5 |
| | 22 |
| | 51 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 306 |
| | $ | (7 | ) | | | $ | 372 |
| | $ | 233 |
|
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Exelon | $ | (219 | ) | | $ | 767 |
| | $ | 1,191 |
|
Generation | (981 | ) | | (531 | ) | | (734 | ) |
ComEd | 534 |
| | 789 |
| | 169 |
|
PECO | (39 | ) | | 50 |
| | (263 | ) |
BGE | 156 |
| | 22 |
| | (21 | ) |
Pepco | 193 |
| | 219 |
| | — |
|
DPL | 32 |
| | 64 |
| | 67 |
|
ACE | 105 |
| | 5 |
| | 22 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | | Predecessor |
| 2018 | 2017 | | March 24, 2016 to December 31, 2016 | | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 330 |
| $ | 306 |
| | $ | (7 | ) | | | | $ | 372 |
|
Debt
See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further detailsadditional information of the Registrants’ debt issuances and retirements. Debt activity for 2018, 2017 2016 and 20152016 by Registrant was as follows:
During the year ended December 31, 2017,2018, the following long-term debt was issued:
|
| | | | | | | | | | | | | |
Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
Exelon Corporate | | Junior Subordinated Notes | | 3.50 | % | | June 1, 2022 | | $ | 1,150 |
| | Refinance Exelon's Junior Subordinated Notes issued in June 2014. |
Generation | | Albany Green Energy Project Financing (a) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 14 |
| | Albany Green Energy biomass generation development. |
Generation | | Energy Efficiency Project Financing (a) | | 3.90 | % | | February 1, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. |
Generation | | Energy Efficiency Project Financing (a) | | 3.72 | % | | May 1, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. |
| | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
Generation | | Energy Efficiency Project Financing (a) | | 2.61 | % | | September 30, 2018 | | $ | 13 |
| | Funding to install energy conservation measures for the Pensacola project. | | Energy Efficiency Project Financing(a) | | 3.72 | % | | March 31, 2019 | | $ | 4 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. |
Generation | | Energy Efficiency Project Financing (a) | | 3.53 | % | | April 1, 2019 | | $ | 8 |
| | Funding to install energy conservation measures for the State Department project. | | Energy Efficiency Project Financing(a) | | 3.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures in Brooklyn, NY. |
Generation | | Senior Notes | | 2.95 | % | | January 15, 2020 | | $ | 250 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Pensacola project. |
Generation | | Senior Notes | | 3.40 | % | | March 15, 2022 | | $ | 500 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. | | Energy Efficiency Project Financing(a) | | 4.17 | % | | January 31, 2019 | | $ | 1 |
| | Funding to install energy conservation measures for the General Services Administration Philadelphia project. |
Generation | | ExGen Texas Power Nonrecourse Debt (b)(c) | | LIBOR + 4.75% |
| | September 18, 2021 | | $ | 6 |
| | General corporate purposes. | | Energy Efficiency Project Financing(a) | | 4.26 | % | | May 31, 2019 | | $ | 3 |
| | Funding to install energy conservation measures for the National Institutes of Health Multi-Buildings Phase II project. |
Generation | | ExGen Renewables IV, Nonrecourse Debt (b) | | LIBOR + 3.00% |
| | November 30, 2024 | | $ | 850 |
| | General corporate purposes. | |
ComEd | | First Mortgage Bonds, Series 122 | | 2.95 | % | | August 15, 2027 | | $ | 350 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | | First Mortgage Bonds, Series 124 | | 4.00 | % | | March 1, 2048 | | $ | 800 |
| | Refinance one series of maturing first mortgage bonds, to repay a portion of ComEd’s outstanding commercial paper obligations and to fund general corporate purposes |
ComEd | | First Mortgage Bonds, Series 123 | | 3.75 | % | | August 15, 2047 | | $ | 650 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. | | First Mortgage Bonds, Series 125 | | 3.70 | % | | August 15, 2028 | | $ | 550 |
| | Repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. |
PECO | | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Refinance a portion of maturing mortgage bonds. |
PECO | | | Loan Agreement | | 2.00 | % | | June 20, 2023 | | $ | 50 |
| | Funding to implement Electric Long-term Infrastructure Improvement Plan |
PECO | | First and Refunding Mortgage Bonds | | 3.70 | % | | September 15, 2047 | | $ | 325 |
| | General corporate purposes. | | First and Refunding Mortgage Bonds | | 3.90 | % | | March 1, 2048 | | $ | 325 |
| | Satisfy short-term borrowings from the Exelon intercompany money pool and for general corporate purposes. |
BGE | | Senior Notes | | 3.75 | % | | August 15, 2047 | | $ | 300 |
| | Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes.
| | Senior Notes | | 4.25 | % | | September 15, 2048 | | $ | 300 |
| | Repay commercial paper obligations and for general corporate purposes. |
Pepco | | Energy Efficiency Project Financing (a) | | 3.30 | % | | December 15, 2017 | | $ | 2 |
| | Funding to install energy conservation measures for the DOE Germantown project. | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. |
Pepco | | First Mortgage Bonds | | 4.15 | % | | March 15, 2043 | | $ | 200 |
| | Funding to repay outstanding commercial paper and for general corporate purposes. | | First Mortgage Bonds | | 4.31 | % | | November 1, 2048 | | $ | 100 |
| | Repay outstanding commercial paper and for general corporate purposes. |
DPL | | | First Mortgage Bonds | | 4.27 | % | | June 15, 2048 | | $ | 200 |
| | Repay outstanding commercial paper and for general corporate purposes. |
ACE | | | First Mortgage Bonds | | 4.00 | % | | October 15, 2028 | | $ | 350 |
| | Refinance ACE’s 7.75% First Mortgage Bonds due November 15, 2018, reduce short-term borrowings and for general corporate purposes. |
__________
| |
(a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
During 2017, the following long term debt was issued:
|
| | | | | | | | | | | | | |
Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
Exelon Corporate | | Junior Subordinated Notes | | 3.50 | % | | June 1, 2022 | | $ | 1,150 |
| | Refinance Exelon's Junior Subordinated Notes issued in June 2014. |
Generation | | Albany Green Energy Project Financing(a) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 14 |
| | Albany Green Energy biomass generation development. |
Generation | | Energy Efficiency Project Financing(a) | | 3.90 | % | | February 1, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. |
Generation | | Energy Efficiency Project Financing(a) | | 3.72 | % | | May 1, 2018 | | $ | 5 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. |
Generation | | Energy Efficiency Project Financing(a) | | 2.61 | % | | September 30, 2018 | | $ | 13 |
| | Funding to install energy conservation measures for the Pensacola project. |
Generation | | Energy Efficiency Project Financing(a) | | 3.53 | % | | April 1, 2019 | | $ | 8 |
| | Funding to install energy conservation measures for the State Department project. |
Generation | | Senior Notes | | 2.95 | % | | January 15, 2020 | | $ | 250 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. |
Generation | | Senior Notes | | 3.40 | % | | March 15, 2020 | | $ | 500 |
| | Repay outstanding commercial paper obligations and for general corporate purposes. |
Generation | | ExGen Texas Power Nonrecourse Debt(b)(c) | | LIBOR + 4.75% |
| | September 18, 2021 | | $ | 6 |
| | General corporate purposes. |
Generation | | ExGen Renewables IV, Nonrecourse Debt(b) | | LIBOR + 3.00% |
| | November 30, 2024 | | $ | 850 |
| | General corporate purposes. |
ComEd | | First Mortgage Bonds, Series 122 | | 2.95 | % | | August 15, 2027 | | $ | 350 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes |
ComEd | | First Mortgage Bonds, Series 123 | | 3.75 | % | | August 15, 2047 | | $ | 650 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd’s outstanding commercial paper obligations and for general corporate purposes. |
PECO | | First and Refunding Mortgage Bonds | | 3.70 | % | | September 15, 2047 | | $ | 325 |
| | General corporate purposes. |
BGE | | Senior Notes | | 3.75 | % | | August 15, 2047 | | $ | 300 |
| | Redeem $250 million in principal amount of the 6.20% Deferrable Interest Subordinated Debentures due October 15, 2043 issued by BGE's affiliate BGE Capital Trust II, repay commercial paper obligations and for general corporate purposes. |
Pepco | | Energy Efficiency Project Financing(a) | | 3.30 | % | | December 15, 2017 | | $ | 2 |
| | Funding to install energy conservation measures for the DOE Germantown project. |
Pepco | | First Mortgage Bonds | | 4.15 | % | | March 15, 2043 | | $ | 200 |
| | Funding to repay outstanding commercial paper and for general corporate purposes. |
__________
| |
(a) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
| |
(b) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of nonrecourse debt. |
| |
(c) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for further discussion.additional information. |
During the year ended December 31, 2016, the following long term debtterm-debt was issued:
| | Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds | | 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. | | 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. | | 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. | | Senior Unsecured Notes | | 4.45 | % | | April 15, 2046 | | $ | 750 |
| | Repay commercial paper issued by PHI and for general corporate purposes. |
Generation | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11 | % | | March 31, 2035 | | $ | 150 |
| | Paydown long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes. | | Renewable Power Generation Nonrecourse Debt(a)
| | 4.11 | % | | March 31, 2035 | | $ | 150 |
| | Paydown long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes. |
Generation | | Albany Green Energy Project Financing (b) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 98 |
| | Albany Green Energy biomass generation development | | Albany Green Energy Project Financing(b) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 98 |
| | Albany Green Energy biomass generation development. |
Generation | | Energy Efficiency Project Financing (b) | | 3.17 | % | | December 31, 2017 | | $ | 16 |
| | Funding to install energy conservation measures in Brooklyn, NY. | | Energy Efficiency Project Financing(b) | | 3.17 | % | | December 31, 2017 | | $ | 16 |
| | Funding to install energy conservation measures in Brooklyn, NY. |
Generation | | Energy Efficiency Project Financing (b) | | 3.90 | % | | January 31, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. | | Energy Efficiency Project Financing(b) | | 3.90 | % | | January 31, 2018 | | $ | 19 |
| | Funding to install energy conservation measures for the Naval Station Great Lakes project. |
Generation | | Energy Efficiency Project Financing (b) | | 3.52 | % | | April 30, 2018 | | $ | 14 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. | | Energy Efficiency Project Financing(b) | | 3.52 | % | | April 30, 2018 | | $ | 14 |
| | Funding to install energy conservation measures for the Smithsonian Zoo project. |
Generation | | SolGen Nonrecourse Debt (a) | | 3.93 | % | | September 30, 2036 | | $ | 150 |
| | General corporate purposes. | | SolGen Nonrecourse Debt(a) | | 3.93 | % | | September 30, 2036 | | $ | 150 |
| | General corporate purposes. |
Generation | | Energy Efficiency Project Financing (b) | | 3.46 | % | | October 1, 2018 | | $ | 36 |
| | Funding to install energy conservation measures or the Marine Corps Logistics Base project. | | Energy Efficiency Project Financing(b) | | 3.46 | % | | October 1, 2018 | | $ | 36 |
| | Funding to install energy conservation measures or the Marine Corps Logistics Base project. |
Generation | | Energy Efficiency Project Financing (b) | | 2.61 | % | | September 30, 2018 | | $ | 4 |
| | Funding to install energy conservation measures for the Pensacola project | | Energy Efficiency Project Financing(b) | | 2.61 | % | | September 30, 2018 | | $ | 4 |
| | Funding to install energy conservation measures for the Pensacola project. |
ComEd | | First Mortgage Bonds, Series 120 | | 2.55 | % | | June 15, 2026 | | $ | 500 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. | | First Mortgage Bonds, Series 120 | | 2.55 | % | | June 15, 2026 | | $ | 500 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. |
ComEd | | First Mortgage Bonds, Series 121 | | 3.65 | % | | June 15, 2046 | | $ | 700 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. | | First Mortgage Bonds, Series 121 | | 3.65 | % | | June 15, 2046 | | $ | 700 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. |
PECO | | First Mortgage Bonds | | 1.70 | % | | September 15, 2021 | | $ | 300 |
| | Refinance maturing mortgage bonds. | | First Mortgage Bonds | | 1.70 | % | | September 15, 2021 | | $ | 300 |
| | Refinance maturing mortgage bonds. |
BGE | | Notes | | 2.40 | % | | August 15, 2026 | | $ | 350 |
| | Redeem the $190M of outstanding preference shares and for general corporate purposes. | | 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. | | Notes | | 3.50 | % | | August 15, 2046 | | 500 | | Redeem the $190M of outstanding preference shares and for general corporate purposes. |
Pepco | | Energy Efficiency Project Financing(b) | | 3.30 | % | | December 15, 2017 | | $ | 4 |
| | Funding to install energy conservation measures for the DOE Germantown project. | | Energy Efficiency Project Financing(b) | | 3.30 | % | | December 15, 2017 | | 4 | | Funding to install energy conservation measures for the DOE Germantown project. |
DPL | | First Mortgage Bonds | | 4.15 | % | | May 15, 2045 | | $ | 175 |
| | Refinance maturing mortgage bonds, repay commercial paper and for general corporate purposes. | | First Mortgage Bonds | | 4.15 | % | | May 15, 2045 | | 175 | | Refinance maturing mortgage bonds, repay commercial paper and for general corporate purposes. |
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of nonrecourse debt. |
| |
(b) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
During the year ended December 31, 2015,2018, the following long term-debtlong-term debt was issued:retired and/or redeemed:
|
| | | | | | | | | | | | | |
Company | | Type | | Interest Rate | | Maturity | | Amount | | Use of Proceeds |
Exelon Corporate | | Senior Unsecured Notes | | 1.55 | % | | June 9, 2017 | | $ | 550 |
| | Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes. |
Exelon Corporate | | Senior Unsecured Notes | | 2.85 | % | | June 15, 2020 | | $ | 900 |
| | Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes. |
Exelon Corporate | | Senior Unsecured Notes | | 3.95 | % | | June 15, 2025 | | $ | 1,250 |
| | Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes. |
Exelon Corporate | | Senior Unsecured Notes | | 4.95 | % | | June 15, 2035 | | $ | 500 |
| | Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes. |
Exelon Corporate | | Senior Unsecured Notes | | 5.10 | % | | June 15, 2045 | | $ | 1,000 |
| | Finance a portion of the pending merger with PHI and related costs and expenses and for general corporate purposes. |
Exelon Corporate | | Long-Term Software License Agreement | | 3.95 | % | | May 1, 2024 | | $ | 111 |
| | Procurement of software licenses. |
Generation | | Senior Unsecured Notes | | 2.95 | % | | January 15, 2020 | | $ | 750 |
| | Fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes and for general corporate purposes. |
Generation | | AVSR DOE Nonrecourse Debt(a) | | 2.29 - 2.96% |
| | January 5, 2037 | | $ | 39 |
| | Antelope Valley solar development. |
Generation | | Energy Efficiency Project Financing(b) | | 3.71 | % | | July 31, 2017 | | $ | 42 |
| | Funding to install energy conservation measures in Coleman, Florida. |
| | Company | | | Type | | Interest Rate | | Maturity | | Amount |
Exelon Corporate | | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 6 |
|
Generation | | | Naval Station Great Lakes Project Financing | | 3.90% | | June 30, 2018 | | $ | 41 |
|
Generation | | | Smithsonian Zoo Project Financing | | 3.72% | | March 31, 2019 | | $ | 1 |
|
Generation | | | Pensacola Project Financing | | 2.61% | | September 30, 2018 | | $ | 21 |
|
Generation | | | Fort Detrick Project Financing | | 3.55% | | June 30, 2019 | | $ | 19 |
|
Generation | | | Holyoke Nonrecourse Debt(a) | | 5.25% | | December 31, 2031 | | $ | 1 |
|
Generation | | | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 10 |
|
Generation | | | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
|
Generation | | | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 33 |
|
Generation | | Energy Efficiency Project Financing(b) | | 3.55 | % | | November 15, 2016 | | $ | 19 |
| | Funding to install energy conservation measures in Frederick, Maryland. | | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 11 |
|
Generation | | Tax Exempt Pollution Control Revenue Bonds | | 2.50 - 2.70% |
| | 2019 - 2020 | | $ | 435 |
| | General corporate purposes. | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
|
Generation | | Albany Green Energy Project Financing(b) | | LIBOR + 1.25% |
| | November 17, 2017 | | $ | 100 |
| | Albany Green Energy biomass generation development. | | ExGen Renewables IV Nonrecourse Debt | | 3mL+300 bps | | November 30, 2024 | | $ | 16 |
|
Generation | | Nuclear Fuel Purchase Contract | | 3.15 | % | | September 30, 2020 | | $ | 57 |
| | Procurement of uranium. | | NUKEM | | 3.15% - 3.35% | | 2018 - 2020 | | $ | 43 |
|
ComEd | | First Mortgage Bonds, Series 118 | | 3.70 | % | | March 1, 2045 | | $ | 400 |
| | Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. | | First Mortgage Bonds | | 5.80% | | March 15, 2018 | | $ | 700 |
|
ComEd | | First Mortgage Bonds, Series 119 | | 4.35 | % | | November 15, 2045 | | $ | 450 |
| | Repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes. | | Notes | | 6.95% | | July 15, 2018 | | $ | 140 |
|
PECO | | First and Refunding Mortgage Bonds | | 3.15 | % | | October 15, 2025 | | $ | 350 |
| | General corporate purposes | | First Mortgage Bonds | | 5.35% | | March 1, 2018 | | $ | 500 |
|
DPL | | | Medium Term Notes, Unsecured | | 6.81% | | January 9, 2018 | | $ | 4 |
|
Pepco | | First Mortgage Bonds | | 4.15 | % | | March 15, 2043 | | $ | 200 |
| | Repay outstanding commercial paper obligations and general corporate purposes | | Notes | | 3.30% | | August 31, 2018 | | $ | 5 |
|
DPL | | First Mortgage Bonds | | 4.15 | % | | May 15, 2045 | | $ | 200 |
| | Repay outstanding commercial paper obligations and general corporate purposes | |
Pepco | | | Third Party Financing | | 7.28-7.99% | | 2021 - 2023 | | $ | 1 |
|
ACE | | First Mortgage Bonds | | 3.50 | % | | December 1, 2025 | | $ | 150 |
| | Repay outstanding commercial paper obligations and general corporate purposes | | First Mortgage Bonds | | 7.75% | | November 15, 2018 | | $ | 250 |
|
ACE | | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 31 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of nonrecourse debt. |
| |
(b) | For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. |
During the year ended December 31, 2017, the following long-term debt was retired and/or redeemed:
| | Company | | Type | | Interest Rate | | Maturity | | Amount | | Type | | Interest Rate | | Maturity | | Amount |
Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 24 |
| | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 24 |
|
Exelon Corporate | | Senior Notes | | 1.55% | | June 9, 2017 | | $ | 550 |
| | Senior Notes | | 1.55% | | June 9, 2017 | | $ | 550 |
|
Generation | | Senior Notes - Exelon Wind | | 2.00% | | July 31, 2017 | | $ | 1 |
| | Senior Notes - Exelon Wind | | 2.00% | | July 31, 2017 | | $ | 1 |
|
Generation | | CEU Upstream Nonrecourse Debt (a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 6 |
| | CEU Upstream Nonrecourse Debt(a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 6 |
|
Generation | | SolGen Nonrecourse Debt (a) | | 3.93% | | September 30, 2036 | | $ | 2 |
| | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 2 |
|
Generation | | AVSR DOE Nonrecourse Debt (a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
|
Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 2 |
| | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 2 |
|
Generation | | Continental Wind Nonrecourse Debt (a) | | 6.00% | | February 28, 2033 | | $ | 31 |
| | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 31 |
|
Generation | | PES - PGOV Notes Payable | | 6.70-7.60% | | 2017 - 2018 | | $ | 1 |
| | PES - PGOV Notes Payable | | 6.70-7.60% | | 2017 - 2018 | | $ | 1 |
|
Generation | | ExGen Texas Power Nonrecourse Debt (a)(b) | | LIBOR + 4.75% | | September 18, 2021 | | $ | 665 |
| | ExGen Texas Power Nonrecourse Debt(a)(b) | | LIBOR + 4.75% | | September 18, 2021 | | $ | 665 |
|
Generation | | Renewable Power Generation Nonrecourse Debt (a) | | 4.11% | | March 31, 2035 | | $ | 14 |
| | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 14 |
|
Generation | | NUKEM | | 3.25% - 3.35% | | June 30, 2018 | | $ | 23 |
| | NUKEM | | 3.25% - 3.35% | | June 30, 2018 | | $ | 23 |
|
Generation | | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 233 |
| | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 233 |
|
Generation | | Senior Notes | | 6.20% | | October 1, 2017 | | $ | 700 |
| | Senior Notes | | 6.20% | | October 1, 2017 | | $ | 700 |
|
Generation | | Albany Green Energy Project Financing | | LIBOR + 1.25% | | November 17, 2017 | | $ | 212 |
| | Albany Green Energy Project Financing | | LIBOR + 1.25% | | November 17, 2017 | | $ | 212 |
|
ComEd | | First Mortgage Bonds | | 6.15% | | September 15, 2017 | | $ | 425 |
| | First Mortgage Bonds | | 6.15% | | September 15, 2017 | | $ | 425 |
|
BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 41 |
| | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 41 |
|
BGE | | Capital Trust Preferred Securities | | 6.20% | | October 15, 2043 | | $ | 258 |
| | Capital Trust Preferred Securities | | 6.20% | | October 15, 2043 | | $ | 258 |
|
PHI | | Senior Notes | | 6.13% | | June 1, 2017 | | $ | 81 |
| | Senior Notes | | 6.13% | | June 1, 2017 | | $ | 81 |
|
DPL | | Medium Term Notes, Unsecured | | 7.56% - 7.58% | | February 1, 2017 | | $ | 14 |
| | Medium Term Notes, Unsecured | | 7.56% - 7.58% | | February 1, 2017 | | $ | 14 |
|
DPL | | Variable Rate Demand Bonds | | Variable | | October 1, 2017 | | $ | 26 |
| | Variable Rate Demand Bonds | | Variable | | October 1, 2017 | | $ | 26 |
|
Pepco | | Third Party Financing | | 6.97% - 7.99% | | 2018 - 2022 | | $ | 1 |
| | Third Party Financing | | 6.97% - 7.99% | | 2018 - 2022 | | $ | 1 |
|
ACE | | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 35 |
| | Transition Bonds | | 5.05% - 5.55% | | 2020 - 2023 | | $ | 35 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of nonrecourse debt. |
| |
(b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions for further discussion.additional information. |
During the year ended December 31, 2016, the following long-term debt was retired and/or redeemed:
| | Company | | Type | | Interest Rate | | Maturity | | Amount | | Type | | Interest Rate | | Maturity | | Amount |
Exelon Corporate | | Long Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 8 |
| | Long Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 8 |
|
Exelon Corporate | | Senior Notes | | 4.95% | | June 15, 2035 | | $ | 1 |
| | Senior Notes | | 4.95% | | June 15, 2035 | | $ | 1 |
|
Generation | | AVSR DOE Nonrecourse Debt (a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
| | Antelope Valley DOE Nonrecourse Debt(a) | | 2.29% - 3.56% | | January 5, 2037 | | $ | 22 |
|
Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
| | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 4 |
|
Generation | | Continental Wind Nonrecourse Debt (a) | | 6.00% | | February 28, 2033 | | $ | 29 |
| | Continental Wind Nonrecourse Debt(a) | | 6.00% | | February 28, 2033 | | $ | 29 |
|
Generation | | CEU Upstream Nonrecourse Debt (a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 46 |
| | CEU Upstream Nonrecourse Debt(a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 46 |
|
Generation | | ExGen Texas Power Nonrecourse Debt (a)(b) | | 5.00% | | September 18, 2021 | | $ | 7 |
| | ExGen Texas Power Nonrecourse Debt(a)(b) | | 5.00% | | September 18, 2021 | | $ | 7 |
|
Generation | | Sacramento Solar Nonrecourse Debt | | LIBOR + 2.25% | | December 31, 2030 | | $ | 33 |
| | Sacramento Solar Nonrecourse Debt | | LIBOR + 2.25% | | December 31, 2030 | | $ | 33 |
|
Generation | | Clean Horizons Nonrecourse Debt | | LIBOR + 2.25% | | September 7, 2030 | | $ | 32 |
| | Clean Horizons Nonrecourse Debt | | LIBOR + 2.25% | | September 7, 2030 | | $ | 32 |
|
Generation | | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 24 |
| | ExGen Renewables I, Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 24 |
|
Generation | | PES - PGOV Notes Payable | | 6.70% - 7.46% | | 2017-2018 | | $ | 1 |
| | PES - PGOV Notes Payable | | 6.70% - 7.46% | | 2017-2018 | | $ | 1 |
|
Generation | | NUKEM | | 3.35% | | June 30, 2018 | | $ | 12 |
| | NUKEM | | 3.35% | | June 30, 2018 | | $ | 12 |
|
Generation | | NUKEM | | 3.25% | | July 1, 2018 | | $ | 10 |
| | NUKEM | | 3.25% | | July 1, 2018 | | $ | 10 |
|
Generation | | Renewable Power Generation Nonrecourse Debt (a) | | 4.11% | | March 31, 2035 | | $ | 9 |
| | Renewable Power Generation Nonrecourse Debt(a) | | 4.11% | | March 31, 2035 | | $ | 9 |
|
Generation | | SolGen Nonrecourse Debt (a) | | 3.93% | | September 30, 2036 | | $ | 2 |
| | SolGen Nonrecourse Debt(a) | | 3.93% | | September 30, 2036 | | $ | 2 |
|
ComEd | �� | First Mortgage Bonds, Series 104 | | 5.95% | | August 15, 2016 | | $ | 415 |
| | First Mortgage Bonds, Series 104 | | 5.95% | | August 15, 2016 | | $ | 415 |
|
ComEd | | First Mortgage Bonds, Series 111 | | 1.95% | | August 1, 2016 | | $ | 250 |
| | First Mortgage Bonds, Series 111 | | 1.95% | | August 1, 2016 | | $ | 250 |
|
PECO | | First and Refunding Mortgage Bonds | | 1.20% | | October 15, 2016 | | $ | 300 |
| | First and Refunding Mortgage Bonds | | 1.20% | | October 15, 2016 | | $ | 300 |
|
BGE | | Rate Stabilization Bonds | | 5.72% | | April 1, 2016 | | $ | 1 |
| | Rate Stabilization Bonds | | 5.72% | | April 1, 2016 | | $ | 1 |
|
BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 38 |
| | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 38 |
|
BGE | | Notes | | 5.90% | | October 1, 2016 | | $ | 300 |
| | Notes | | 5.90% | | October 1, 2016 | | $ | 300 |
|
BGE | | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 40 |
| | Rate Stabilization Bonds | | 5.82% | | April 1, 2017 | | $ | 40 |
|
PHI | | Senior Unsecured Notes | | 5.90% | | December 12, 2016 | | $ | 190 |
| | Senior Unsecured Notes | | 5.90% | | December 12, 2016 | | $ | 190 |
|
DPL | | First Mortgage Bonds | | 5.22% | | December 30, 2016 | | $ | 100 |
| | First Mortgage Bonds | | 5.22% | | December 30, 2016 | | $ | 100 |
|
ACE | | Transition Bonds | | 5.05% | | October 20, 2020 | | $ | 12 |
| | Transition Bonds | | 5.05% | | October 20, 2020 | | $ | 12 |
|
ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | $ | 34 |
| | Transition Bonds | | 5.55% | | October 20, 2023 | | $ | 34 |
|
ACE | | First Mortgage Bonds | | 7.68% | | August 23, 2016 | | $ | 2 |
| | First Mortgage Bonds | | 7.68% | | August 23, 2016 | | $ | 2 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of nonrecourse debt. |
| |
(b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions for further discussion.additional information. |
During the year ended December 31, 2015, the following long-term debt was retired and/or redeemed:
|
| | | | | | | | | | |
Company | | Type | | Interest Rate | | Maturity | | Amount |
Exelon Corporate | | Senior Unsecured Notes | | 4.55% | | June 15, 2015 | | $ | 550 |
|
Exelon Corporate | | Senior Notes | | 4.90% | | June 15, 2015 | | $ | 800 |
|
Exelon Corporate | | Senior Unsecured Notes | | 3.95% | | June 15, 2025 | | $ | 443 |
|
Exelon Corporate | | Senior Unsecured Notes | | 4.95% | | June 15, 2035 | | $ | 167 |
|
Exelon Corporate | | Senior Unsecured Notes | | 5.10% | | June 15, 2045 | | $ | 259 |
|
Exelon Corporate | | Long-Term Software License Agreement | | 3.95% | | May 1, 2024 | | $ | 1 |
|
Generation | | Senior Unsecured Notes | | 4.55% | | June 15, 2015 | | $ | 550 |
|
Generation | | CEU Upstream Nonrecourse Debt (a) | | LIBOR + 2.25% | | January 14, 2019 | | $ | 9 |
|
Generation | | AVSR DOE Nonrecourse Debt (a) | | 2.29%-3.56% | | January 5, 2037 | | $ | 23 |
|
Generation | | Kennett Square Capital Lease | | 7.83% | | September 20, 2020 | | $ | 3 |
|
Generation | | Continental Wind Nonrecourse Debt | | 6.00% | | February 28, 2033 | | $ | 20 |
|
Generation | | ExGen Texas Power Nonrecourse Debt (a)(b) | | LIBOR + 4.75% | | September 8, 2021 | | $ | 5 |
|
Generation | | ExGen Renewables I Nonrecourse Debt | | LIBOR + 4.25% | | February 6, 2021 | | $ | 24 |
|
Generation | | Constellation Solar Horizons Nonrecourse Debt | | 2.56% | | September 7, 2030 | | $ | 2 |
|
Generation | | Sacramento PV Energy Nonrecourse Debt | | 2.58% | | December 31, 2030 | | $ | 2 |
|
Generation | | Energy Efficiency Project (b) | | 3.55% | | November 15, 2016 | | $ | 19 |
|
ComEd | | First Mortgage Bonds, Series 101 | | 4.70% | | April 15, 2015 | | $ | 260 |
|
BGE | | Rate Stabilization Bonds | | 5.72% | | April 1, 2016 | | $ | 75 |
|
PHI | | Senior Unsecured Notes | | 2.70% | | October 1, 2015 | | $ | 250 |
|
PHI (c) | | Energy Efficiency Project Financing | | 4.68% | | February 10, 2015 | | $ | 7 |
|
PHI (c) | | Energy Efficiency Project Financing | | 8.87% | | June 1, 2021 | | $ | 5 |
|
PHI (c) | | Energy Efficiency Project Financing | | 7.61% | | August 1, 2015 | | $ | 1 |
|
PHI (c) | | PES - PGOV Notes Payable | | 6.70% | | 2017-2018 | | $ | 1 |
|
Pepco | | Energy Efficiency Project Financing | | 3.12% | | February 20, 2015 | | $ | 12 |
|
DPL | | Senior Unsecured Notes | | 5.00% | | June 1, 2015 | | $ | 100 |
|
ACE | | Secured Medium-Term Notes Series C | | 7.68% | | August 24, 2015 | | $ | 15 |
|
ACE | | Transition Bonds | | 5.05% | | October 20, 2020 | | $ | 12 |
|
ACE | | Transition Bonds | | 5.55% | | October 20, 2023 | | $ | 32 |
|
__________
| |
(a) | See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt. |
| |
(b) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial statements. Refer to Note 4 — Mergers, Acquisitions and Dispositions for further discussion. |
| |
(c) | Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES financing was included with Generation. |
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases or other viable options to reduce debt on their respective balance sheets.
Dividends
Cash dividend payments and distributions for the year ended December 31, 2018, 2017 2016 and 20152016 by Registrant were as follows:
| | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Exelon | $ | 1,236 |
| | $ | 1,166 |
| | $ | 1,105 |
| $ | 1,332 |
| | $ | 1,236 |
| | $ | 1,166 |
|
Generation | 659 |
| | 922 |
| | 2,474 |
| 1,001 |
| | 659 |
| | 922 |
|
ComEd | 422 |
| | 369 |
| | 299 |
| 459 |
| | 422 |
| | 369 |
|
PECO | 288 |
| | 277 |
| | 279 |
| 306 |
| | 288 |
| | 277 |
|
BGE(a) | 198 |
| | 187 |
| | 171 |
| 209 |
| | 198 |
| | 187 |
|
Pepco | 133 |
| | 136 |
| | 146 |
| 169 |
| | 133 |
| | 136 |
|
DPL | 112 |
| | 54 |
| | 92 |
| 96 |
| | 112 |
| | 54 |
|
ACE | 68 |
| | 63 |
| | 12 |
| 59 |
| | 68 |
| | 63 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 311 |
| | $ | 273 |
| | | $ | — |
| | $ | 275 |
|
|
| | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2018 | | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 326 |
| | $ | 311 |
| $ | 273 |
| | | $ | — |
|
__________
| |
(a) | Includes dividends paid on BGE's preference stock during 2016 and 2015.2016. |
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 20172018 and for the first quarter of 20182019 were as follows:
|
| | | | | | | | | | |
Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share |
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 |
|
Third Quarter 2017 | | July 25, 2017 | | August 15, 2017 | | September 8, 2017 | | $ | 0.3275 |
|
Fourth Quarter 2017 | | September 25, 2017 | | November 15, 2017 | | December 8, 2017 | | $ | 0.3275 |
|
First Quarter 2018(a) | | January 30, 2018 | | February 15, 2018 | | March 9, 2018 | | $ | 0.3450 |
|
|
| | | | | | | | | | |
Period | | Declaration Date | | Shareholder of Record Date | | Dividend Payable Date | | Cash per Share(a) |
First Quarter 2018 | | January 30, 2018 | | February 15, 2018 | | March 9, 2018 | | $ | 0.3450 |
|
Second Quarter 2018 | | May 1, 2018 | | May 15, 2018 | | June 8, 2018 | | $ | 0.3450 |
|
Third Quarter 2018 | | July 24, 2018 | | August 15, 2018 | | September 10, 2018 | | $ | 0.3450 |
|
Fourth Quarter 2018 | | September 24, 2018 | | November 15, 2018 | | December 1, 2018 | | $ | 0.3450 |
|
First Quarter 2019 | | February 5, 2019 | | February 20, 2019 | | March 8, 2019 | | $ | 0.3625 |
|
___________
| |
(a) | Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the March 2018 dividend. |
Short-Term Borrowings
Short-term borrowings incurred (repaid) during 2018, 2017 2016 and 20152016 by Registrant were as follows:
| |
| 2017 |
| 2016 |
| 2015 | 2018 |
| 2017 |
| 2016 |
Exelon | $ | (261 | ) | | $ | (353 | ) | | $ | 80 |
| $ | (338 | ) | | $ | (261 | ) | �� | $ | (353 | ) |
Generation | (620 | ) | | 620 |
| | — |
| — |
| | (620 | ) | | 620 |
|
ComEd | — |
| | (294 | ) | | (10 | ) | — |
| | — |
| | (294 | ) |
BGE | 32 |
| | (165 | ) | | 90 |
| (42 | ) | | 32 |
| | (165 | ) |
Pepco | 3 |
| | (41 | ) | | (40 | ) | 14 |
| | 3 |
| | (41 | ) |
DPL | 216 |
| | (105 | ) | | (1 | ) | (216 | ) | | 216 |
| | (105 | ) |
ACE | 108 |
| | (5 | ) | | (122 | ) | (94 | ) | | 108 |
| | (5 | ) |
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 328 |
| | $ | (515 | ) | | | $ | (121 | ) | | $ | 34 |
|
|
| | | | | | | | | | | | | | |
| Successor | | | | Predecessor |
| 2018 | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | (296 | ) | $ | 328 |
| $ | (515 | ) | | | $ | (121 | ) |
Retirement of Long-Term Debt to Financing Affiliates
On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities. See Note 13 — Debt and Credit Agreements for further discussion.
Contributions from Parent/Member
Contributions from Parent/Member (Exelon) during 2018, 2017 2016 and 20152016 by Registrant were as follows:
| |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Generation | $ | 102 |
| | $ | 142 |
| | $ | 47 |
| $ | 155 |
| | $ | 102 |
| | $ | 142 |
|
ComEd(a)(b) | 672 |
| | 473 |
| | 209 |
| 500 |
| | 672 |
| | 473 |
|
PECO(b) | 16 |
| | 18 |
| | 16 |
| 89 |
| | 16 |
| | 18 |
|
BGE(b) | 184 |
| | 61 |
| | 7 |
| 109 |
| | 184 |
| | 61 |
|
Pepco(c) | 161 |
| | 187 |
| | 112 |
| 166 |
| | 161 |
| | 187 |
|
DPL(c) | — |
| | 152 |
| | 75 |
| 150 |
| | — |
| | 152 |
|
ACE(c) | — |
| | 139 |
| | 95 |
| 67 |
| | — |
| | 139 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI(b) | $ | 758 |
| | $ | 1,251 |
| | | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
| 2018 | | 2017 | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 385 |
| | $ | 758 |
| $ | 1,251 |
| | | $ | — |
|
__________
| |
(a) | Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and modernization pursuant to EIMA, transmission upgrades and expansions and Exelon's agreement to indemnify ComEd for any unfavorable after-tax impacts associated with ComEd's LKE tax matter. |
| |
(b) | Contribution paid by Exelon. |
| |
(c) | Contribution paid by PHI. |
Pursuant to the orders approving the PHI 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. BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends. As of December 31, 2017,2018, BGE no longer has any preferred stock outstanding. See Note 21 - Earnings Per Shareof the Combined Notes to Consolidated Financial Statements for further details.
Other
For the year ended December 31, 2017,2018, other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements’ for additional information.
Credit Matters
Market Conditions
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$9.7 billion (including bilateral credit facilities and credit facilities for project finance) in aggregate total commitments of which $8.3$8.0 billion was available as of December 31, 2017,2018, and of which no financial institution has more than 7% of the aggregate commitments for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE.the Registrants. The Registrants had access to the commercial paper market during 20172018 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising and merger activity. See PART I. ITEM 1A. RISK FACTORS for furtheradditional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of December 31, 2017,2018, it would have been required to provide incremental collateral of $1.8$2.1 billion to meet collateral obligations for derivatives, non-derivatives, normal purchases and normal sales contracts and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within its currentthe $4.1 billion of available credit facility capacitiescapacity of $4.7 billion.
its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at December 31, 20172018 and available credit facility capacity prior to any incremental collateral at December 31, 2017:2018:
| | | 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 | $ | 18 |
| | $ | — |
| | $ | 998 |
| $ | 9 |
| | $ | — |
| | $ | 998 |
|
PECO | 3 |
| | 34 |
| | 599 |
| — |
| | 39 |
| | 600 |
|
BGE | 3 |
| | 66 |
| | 600 |
| 12 |
| | 69 |
| | 599 |
|
Pepco | 4 |
| | — |
| | 300 |
| 11 |
| | — |
| | 292 |
|
DPL | 1 |
| | 11 |
| | 300 |
| 5 |
| | 11 |
| | 299 |
|
ACE | — |
| | — |
| | 300 |
| — |
| | — |
| | 300 |
|
__________
| |
(a) | Represents incremental collateral related to natural gas procurement contracts. |
Exelon Credit Facilities
Exelon Corporate, ComEd, BGE, Pepco, DPL and BGEACE 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 intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. 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.
See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussionadditional information of the Registrants’ credit facilities and short term borrowing activity.
Other Credit Matters
Capital StructureStructure.. At December 31, 2017,2018, the capital structures of the Registrants consisted of the following:
| |
| Exelon |
| Generation |
| ComEd |
| PECO |
| BGE | | PHI | | Pepco | | DPL | | ACE | Exelon |
| Generation |
| ComEd |
| PECO |
| BGE | | PHI | | Pepco | | DPL | | ACE |
Long-term debt | 51 | % | | 32 | % | | 44 | % | | 44 | % | | 45 | % | | 39 | % | | 50 | % | | 46 | % | | 49 | % | 51 | % | | 32 | % | | 44 | % | | 44 | % | | 46 | % | | 40 | % | | 49 | % | | 50 | % | | 48 | % |
Long-term debt to affiliates(a) | 1 | % | | 4 | % | | 1 | % | | 3 | % | | — | % | | — | % | | — | % | | — | % | | — | % | 1 | % | | 4 | % | | 1 | % | | 3 | % | | — | % | | — | % | | — | % | | — | % | | — | % |
Common equity | 47 | % | | — | % | | 55 | % | | 53 | % | | 54 | % | | — |
| | 49 | % | | 46 | % | | 46 | % | 47 | % | | — | % | | 55 | % | | 53 | % | | 53 | % | | — |
| | 50 | % | | 50 | % | | 46 | % |
Member’s equity | — | % | | 64 | % | | — | % | | — | % | | — | % | | 59 | % | | — |
| | — |
| | — |
| — | % | | 64 | % | | — | % | | — | % | | — | % | | 59 | % | | — |
| | — |
| | — |
|
Commercial paper and notes payable | 1 | % | | — | % | | — |
| | — | % | | 1 | % | | 2 | % | | 1 | % | | 8 | % | | 5 | % | 1 | % | | — | % | | — |
| | — | % | | 1 | % | | 1 | % | | 1 | % | | — | % | | 6 | % |
__________
| |
(a) | Includes approximately $389$390 million, $205 million and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs. |
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 12 — 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 an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of December 31, 2017,2018, are presented in the following tables:
| | Exelon Intercompany Money Pool | For the Year Ended December 31, 2017 | | As of December 31, 2017 | For the Year Ended December 31, 2018 | | As of December 31, 2018 |
Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
Exelon Corporate | $ | 579 |
| | $ | — |
| | $ | 217 |
| $ | 674 |
| | $ | — |
| | $ | 216 |
|
Generation | 20 |
| | (589 | ) | | (54 | ) | 227 |
| | (389 | ) | | (100 | ) |
PECO | 336 |
| | (22 | ) | | — |
| 285 |
| | (420 | ) | | — |
|
BSC | — |
| | (423 | ) | | (217 | ) | — |
| | (403 | ) | | (173 | ) |
PHI Corporate | — |
| | (47 | ) | | — |
| — |
| | (35 | ) | | — |
|
PCI | 55 |
| | — |
| | 54 |
| 57 |
| | (1 | ) | | 57 |
|
| | PHI Intercompany Money Pool | For the Year Ended December 31, 2017 | | As of December 31, 2017 | For the Year Ended December 31, 2018 | | As of December 31, 2018 |
Contributed (borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) | Maximum Contributed | | Maximum Borrowed | | Contributed (Borrowed) |
PHI Corporate | $ | 9 |
| | $ | (2 | ) | | $ | 1 |
| $ | 1 |
| | $ | — |
| | $ | 1 |
|
Pepco | — |
| | — |
| | — |
| |
DPL | — |
| | — |
| | — |
| |
ACE | — |
| | — |
| | — |
| |
PHISCO | 3 |
| | (9 | ) | | — |
| 34 |
| | — |
| | 3 |
|
Investments in Nuclear Decommissioning TrustNDT Funds. Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance with
Generation’s NDT fund investment policy. Generation’s and CENG's investment policies establish limits on the concentration of holdings in any one company and also in any one industry. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for furtheradditional 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 ACE 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.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(a) | | Short-term Financing Authority(a) | | Long-term Financing Authority(a) |
Commission | | Expiration Date | | Amount | Commission | | Expiration Date (c) | | Amount | Commission | | Expiration Date | | Amount | Commission | | Expiration Date | | Amount (c) |
ComEd(b) | | FERC | | December 31, 2019 | | $ | 2,500 |
| | ICC | | 2019 | | $ | 1,383 |
| | FERC | | December 31, 2019 | | $ | 2,500 |
| | ICC | | 2019 & 2021 | | $ | 1,533 |
|
PECO | | FERC | | December 31, 2019 | | 1,500 |
| | PAPUC | | December 31, 2018 | | 1,275 |
| | FERC | | December 31, 2019 | | 1,500 |
| | PAPUC | | December 31, 2021 | | 1,900 |
|
BGE | | FERC | | December 31, 2019 | | 700 |
| | MDPSC | | N/A | | 700 |
| | FERC | | December 31, 2019 | | 700 |
| | MDPSC | | N/A | | 400 |
|
Pepco | | FERC | | December 31, 2019 | | 500 |
| | MDPSC | | September 25, 2017 | | — |
| | FERC | | December 31, 2019 | | 500 |
| | MDPSC / DCPSC | | December 31, 2020 | | 400 |
|
DCPSC | | December 31, 2020 | | 600 |
| |
DPL | | FERC | | December 31, 2019 | | 500 |
| | MDPSC | | December 31, 2017 | | — |
| |
| DPSC | December 31, 2020 | 350 |
| | FERC | | December 31, 2019 | | 500 |
| | MDPSC / DPSC | | December 31, 2020 | | 150 |
|
ACE | | NJBPU | | December 31, 2019 | | 350 |
| | NJBPU | | December 31, 2019 | | 350 |
| | NJBPU | | December 31, 2019 | | 350 |
| | NJBPU | | December 31, 2019 | | — |
|
__________
| |
(a) | Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority. |
| |
(b) | ComEd had $1,140$440 million available in long-term debt refinancing authority and $243$1,093 million available in new money long termlong-term debt financing authority from the ICC as of December 31, 20172018 and has an expiration date of June 1, 2019 and MarchAugust 1, 2019,2021, respectively. |
| |
(c) | Pepco and DPL areACE is currently in the process of renewing theirrequesting its long-term debt financing authority with the MDPSC. authority. |
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. The Federal Power Act declares it
ComEd is subject to be unlawful for any officer or director of any public utility “to participaterestrictions in the making or paying of any dividends of such public utility from any funds properly included in capital account.” In addition, under Illinois law,event that (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd may not pay any dividendFinancing III; (2) it defaults on its stock, unless, among other things,guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.
PECO is subject to restrictions in the event that (1) it exercises its earnings and earned surplusright to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are sufficient to declare and pay a dividend after provision is made for reasonable and proper reserves, or unless ComEd has specific authorization from the ICC. issued.
BGE is subject to certain dividend restrictions established by the MDPSC. First,MDPSC that prohibit BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid.
Pepco, DPL and ACE are subject to certain dividend restrictions established by settlements approved in NJ, DE, MDthe District of Columbia, Maryland, Delaware, and the DC.New Jersey. Pepco, DPL and ACE are prohibited from paying a dividend on their common shares if (a) after the dividend payment, Pepco’s, DPL’sPepco's, DPL's or ACE’sACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the Commissions
DCPSC, MDPSC, DPSC, and the BoardNJBPU or (b) Pepco’s, DPL’sPepco's, DPL's or ACE’sACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%.
At December 31, 2017,2018, Exelon had retained earnings of $13,503$14,766 million, including Generation’s undistributed earnings of $4,310$3,724 million, ComEd’s retained earnings of $1,132$1,337 million consisting of retained earnings appropriated for future dividends of $2,771$2,976 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $1,087$1,242 million, and BGE’s retained earnings $1,536 million. At December 31, 2017, Pepco had retained$1,640 million, and PHI's undistributed earnings of $1,063 million, DPL had retained earnings of $571 million and ACE had retained earnings of $131$62 million. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer restrictions.
Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants’ future estimated cash payments as of December 31, 20172018 under existing contractual obligations, including payments due by period. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future events.
Exelon
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 |
| 2019 - 2020 |
| 2021 - 2022 |
| Due 2023 and beyond | Total | | 2019 |
| 2020 - 2021 |
| 2022 - 2023 |
| Due 2024 and beyond |
Long-term debt(a) | $ | 33,994 |
| | $ | 2,057 |
| | $ | 4,459 |
| | $ | 4,574 |
| | $ | 22,904 |
| $ | 35,265 |
| | $ | 1,328 |
| | $ | 5,033 |
| | $ | 3,933 |
| | $ | 24,971 |
|
Interest payments on long-term debt(b) | 15,999 |
| | 1,346 |
| | 2,579 |
| | 2,231 |
| | 9,843 |
| 22,840 |
| | 1,446 |
| | 2,689 |
| | 2,372 |
| | 16,333 |
|
Capital leases | 53 |
| | 18 |
| | 25 |
| | 2 |
| | 8 |
| 36 |
| | 21 |
| | 6 |
| | 1 |
| | 8 |
|
Operating leases(c)(d) | 1,512 |
| | 188 |
| | 276 |
| | 261 |
| | 787 |
| 1,378 |
| | 140 |
| | 292 |
| | 223 |
| | 723 |
|
Purchase power obligations(d)(e) | 1,153 |
| | 358 |
| | 498 |
| | 103 |
| | 194 |
| 1,121 |
| | 365 |
| | 484 |
| | 98 |
| | 174 |
|
Fuel purchase agreements(e)(f) | 7,270 |
| | 1,229 |
| | 2,241 |
| | 1,385 |
| | 2,415 |
| 5,984 |
| | 1,235 |
| | 2,078 |
| | 1,269 |
| | 1,402 |
|
Electric supply procurement(e)(f) | 3,417 |
| | 2,213 |
| | 1,204 |
| | — |
| | — |
| 2,836 |
| | 1,828 |
| | 1,008 |
| | — |
| | — |
|
AEC purchase commitments(e)(f) | 3 |
| | 1 |
| | 2 |
| | — |
| | — |
| 2 |
| | 1 |
| | 1 |
| | — |
| | — |
|
Curtailment services commitments(e)(f) | 119 |
| | 52 |
| | 54 |
| | 13 |
| | — |
| 129 |
| | 29 |
| | 74 |
| | 26 |
| | — |
|
Long-term renewable energy and REC commitments(f)(g) | 1,666 |
| | 111 |
| | 224 |
| | 235 |
| | 1,096 |
| 1,838 |
| | 137 |
| | 265 |
| | 274 |
| | 1,162 |
|
Other purchase obligations(g)(h) | 7,765 |
| | 4,844 |
| | 1,585 |
| | 561 |
| | 775 |
| 6,626 |
| | 4,676 |
| | 1,323 |
| | 247 |
| | 380 |
|
DC PLUG obligation(h)(i) | 188 |
| | 28 |
| | 60 |
| | 60 |
| | 40 |
| 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
Construction commitments(i)(j) | 57 |
| | 56 |
| | 1 |
| | — |
| | — |
| 21 |
| | 21 |
| | — |
| | — |
| | — |
|
PJM regional transmission expansion commitments(j)(k) | 569 |
| | 179 |
| | 270 |
| | 120 |
| | — |
| 396 |
| | 141 |
| | 237 |
| | 18 |
| | — |
|
SNF obligation(k)(l) | 1,147 |
| | — |
| | — |
| | — |
| | 1,147 |
| 1,171 |
| | — |
| | — |
| | — |
| | 1,171 |
|
Pension contributions(l) | 1,393 |
| | 301 |
| | 493 |
| | 386 |
| | 213 |
| |
ZEC commitments(m) | | 1,404 |
| | 168 |
| | 337 |
| | 332 |
| | 567 |
|
Pension contributions(n) | | 2,276 |
| | 301 |
| | 616 |
| | 752 |
| | 607 |
|
Total contractual obligations | $ | 76,305 |
| | $ | 12,981 |
|
| $ | 13,971 |
|
| $ | 9,931 |
|
| $ | 39,422 |
| $ | 83,483 |
| | $ | 11,867 |
|
| $ | 14,503 |
|
| $ | 9,605 |
|
| $ | 47,508 |
|
__________
| |
(a) | Includes $390 million due after 20232024 to ComEd and PECO financing trusts. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017.2018. Includes estimated interest payments due to ComEd PECO, BGE, PHI, Pepco, DPL and ACEPECO financing trusts. |
| |
(c) | Includes amounts related to shared use land arrangements. |
| |
(d) | Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. Includes estimated cash payments for service fees related to PECO’s meter reading operating lease. |
| |
(d)(e) | Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017, including those related to CENG.2018. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $106$126 million, $99$56 million, $40$35 million, $31$26 million, $19$20 million and $171$155 million for 2018, 2019, 2020, 2021, 2022, 2023 and thereafter, respectively. |
| |
(e)(f) | Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and purchase AECs and curtailment services. |
| |
(f)(g) | Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the earliest and maximum settlements with suppliers for renewable energy and RECs under the existing contract terms. |
| |
(h) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(i) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3—4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(g)(j) | Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2018, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2019. |
| |
(k) | Under their operating agreements with PJM, ComEd, PECO, BGE, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects. |
| |
(l) | See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations. |
| |
(m) | Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up. |
| |
(n) | These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of $300 million until all the qualified plans are fully funded on an ABO basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2024 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding estimated future pension benefit payments. |
Generation
|
| | | | | | | | | | | | | | | | | | | |
| | | Payment due within | | |
| Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 8,745 |
| | $ | 899 |
| | $ | 2,103 |
| | $ | 1,023 |
| | $ | 4,720 |
|
Interest payments on long-term debt(a) | 4,333 |
| | 354 |
| | 592 |
| | 483 |
| | 2,904 |
|
Capital leases | 14 |
| | 7 |
| | 6 |
| | 1 |
| | — |
|
Operating leases(b)(c) | 763 |
| | 33 |
| | 92 |
| | 93 |
| | 545 |
|
Purchase power obligations(d) | 1,121 |
| | 365 |
| | 484 |
| | 98 |
| | 174 |
|
Fuel purchase agreements(e) | 4,931 |
| | 1,013 |
| | 1,759 |
| | 1,078 |
| | 1,081 |
|
Other purchase obligations(f) | 1,742 |
| | 1,114 |
| | 224 |
| | 98 |
| | 306 |
|
Construction commitments(g) | 21 |
| | 21 |
| | — |
| | — |
| | — |
|
SNF obligation(h) | 1,171 |
| | — |
| | — |
| | — |
| | 1,171 |
|
Total contractual obligations | $ | 22,841 |
| | $ | 3,806 |
|
| $ | 5,260 |
|
| $ | 2,874 |
|
| $ | 10,901 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2018. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. |
| |
(d) | Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts represent Generation’s expected payments under these arrangements at December 31, 2018. Expected payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $126 million, $56 million, $35 million, $26 million, $20 million and $155 million for 2019, 2020, 2021, 2022, 2023 and thereafter, respectively. |
| |
(e) | Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG. |
| |
(f) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(h) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(i) | Represents commitments for Generation's ongoing investments in new natural gas and biomass generation construction. |
| |
(j) | Under their operating agreements with PJM, ComEd, PECO, BGE, Pepco, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd, PECO, BGE, Pepco, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(k) | See Note 23 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations. |
| |
(l) | These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of $300 million (which has been updated for the inclusion of PHI) until the qualified plans are fully funded on an accumulated benefit obligation basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under ERISA and the Pension Protection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status. These amounts represent estimates that are based on assumptions that are subject to change. Qualified pension contributions for years after 2023 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit payments. |
Generation
|
| | | | | | | | | | | | | | | | | | | |
| | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond |
Long-term debt | $ | 8,937 |
| | $ | 341 |
| | $ | 2,747 |
| | $ | 1,023 |
| | $ | 4,826 |
|
Interest payments on long-term debt(a) | 4,808 |
| | 391 |
| | 705 |
| | 530 |
| | 3,182 |
|
Capital leases | 18 |
| | 5 |
| | 11 |
| | 2 |
| | — |
|
Operating leases(b) | 817 |
| | 74 |
| | 76 |
| | 94 |
| | 573 |
|
Purchase power obligations(c) | 1,153 |
| | 358 |
| | 498 |
| | 103 |
| | 194 |
|
Fuel purchase agreements(d) | 6,147 |
| | 1,000 |
| | 1,909 |
| | 1,184 |
| | 2,054 |
|
Other purchase obligations(e) | 1,456 |
| | 398 |
| | 249 |
| | 181 |
| | 628 |
|
Construction commitments(f) | 57 |
| | 56 |
| | 1 |
| | — |
| | — |
|
SNF obligation(g) | 1,147 |
| | — |
| | — |
| | — |
| | 1,147 |
|
Total contractual obligations | $ | 24,540 |
| | $ | 2,623 |
|
| $ | 6,196 |
|
| $ | 3,117 |
|
| $ | 12,604 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017. |
| |
(b) | Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power obligations. |
| |
(c) | Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s expected payments under these arrangements at December 31, 2017. Expected |
payments include certain fixed capacity charges which may be reduced based on plant availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $106 million, $99 million, $40 million, $31 million, $19 million and $171 million for 2018, 2019, 2020, 2021, 2022 and thereafter, respectively.
| |
(d) | Represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG. |
| |
(e) | Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(f)(g) | Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2017,2018, the commitments relate to the construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2018.2019. |
| |
(g)(h) | See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for furtheradditional information regarding SNF obligations. |
ComEd
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt(a) | $ | 7,874 |
| | $ | 840 |
| | $ | 800 |
| | $ | 350 |
| | $ | 5,884 |
| $ | 8,385 |
| | $ | 300 |
| | $ | 850 |
| | $ | — |
| | $ | 7,235 |
|
Interest payments on long-term debt(b) | 4,937 |
| | 269 |
| | 517 |
| | 469 |
| | 3,682 |
| 6,512 |
| | 339 |
| | 646 |
| | 614 |
| | 4,913 |
|
Capital leases | 8 |
| | — |
| | — |
| | — |
| | 8 |
| 8 |
| | — |
| | — |
| | — |
| | 8 |
|
Operating leases(c) | 23 |
| | 7 |
| | 10 |
| | 6 |
| | — |
| 23 |
| | 7 |
| | 9 |
| | 7 |
| | — |
|
Electric supply procurement | 741 |
| | 476 |
| | 265 |
| | — |
| | — |
| 650 |
| | 419 |
| | 231 |
| | — |
| | — |
|
Long-term renewable energy and REC commitments(d) | 1,321 |
| | 82 |
| | 166 |
| | 177 |
| | 896 |
| 1,497 |
| | 106 |
| | 203 |
| | 212 |
| | 976 |
|
Other purchase obligations(e) | 1,035 |
| | 927 |
| | 82 |
| | 16 |
| | 10 |
| 1,109 |
| | 1,050 |
| | 55 |
| | 2 |
| | 2 |
|
PJM regional transmission expansion commitments(f) | 164 |
| | 36 |
| | 104 |
| | 24 |
| | — |
| 176 |
| | 40 |
| | 136 |
| | — |
| | — |
|
ZEC commitments(g) | | 1,404 |
| | 168 |
| | 337 |
| | 332 |
| | 567 |
|
Total contractual obligations | $ | 16,103 |
| | $ | 2,637 |
|
| $ | 1,944 |
|
| $ | 1,042 |
|
| $ | 10,480 |
| $ | 19,764 |
| | $ | 2,429 |
|
| $ | 2,467 |
|
| $ | 1,167 |
|
| $ | 13,701 |
|
__________
| |
(a) | Includes $206 million due after 20232024 to a ComEd financing trust. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2017.2018. Includes estimated interest payments due to the ComEd financing trust. |
| |
(c) | AmountsIncludes amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, has excluded these payments from the remaining years as such amounts would not be meaningful. ComEd’s average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.shared use land arrangements. |
| |
(d) | Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum and earliest settlements with suppliers for renewable energy and RECs under the existing contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(f) | Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ComEd’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
In January 2018, ComEd entered into 10-year ZEC procurement contracts with Generation. The following table summarizes ComEd’s future estimated cash payments under the executed contract. See Note 3 — Regulatory Matters and Note 28 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for more information.
|
| | | | | | | | | | | | | | | | | | | |
| | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond |
ZEC commitments(a) | $ | 1,589 |
| | $ | 271 |
| | $ | 327 |
| | $ | 314 |
| | $ | 677 |
|
__________
| |
(a)(g) | Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with no mark-up. |
PECO
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt(a) | $ | 3,109 |
| | $ | 500 |
| | $ | — |
| | $ | 650 |
| | $ | 1,959 |
| $ | 3,309 |
| | $ | — |
| | $ | 300 |
| | $ | 400 |
| | $ | 2,609 |
|
Interest payments on long-term debt(b) | 1,916 |
| | 105 |
| | 210 |
| | 202 |
| | 1,399 |
| 2,562 |
| | 131 |
| | 261 |
| | 242 |
| | 1,928 |
|
Operating leases(c)(d) | 25 |
| | 5 |
| | 10 |
| | 10 |
| | — |
| 25 |
| | 5 |
| | 10 |
| | 10 |
| | — |
|
Fuel purchase agreements(d)(e) | 339 |
| | 113 |
| | 151 |
| | 35 |
| | 40 |
| 335 |
| | 116 |
| | 151 |
| | 33 |
| | 35 |
|
Electric supply procurement(d)(e) | 526 |
| | 420 |
| | 106 |
| | — |
| | — |
| 530 |
| | 453 |
| | 77 |
| | — |
| | — |
|
AEC purchase commitments(d)(e) | 6 |
| | 2 |
| | 4 |
| | — |
| | — |
| 4 |
| | 2 |
| | 2 |
| | — |
| | — |
|
Other purchase obligations(e)(f) | 465 |
| | 257 |
| | 157 |
| | 46 |
| | 5 |
| 668 |
| | 501 |
| | 156 |
| | 10 |
| | 1 |
|
PJM regional transmission expansion commitments(f)(g) | 53 |
| | 16 |
| | 29 |
| | 8 |
| | — |
| 54 |
| | 27 |
| | 18 |
| | 9 |
| | — |
|
Total contractual obligations | $ | 6,439 |
| | $ | 1,418 |
|
| $ | 667 |
|
| $ | 951 |
|
| $ | 3,403 |
| $ | 7,487 |
| | $ | 1,235 |
|
| $ | 975 |
|
| $ | 704 |
|
| $ | 4,573 |
|
__________
| |
(a) | Includes $184 million due after 20232024 to PECO financing trusts. |
| |
(b) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(c) | Includes estimated cash payments for service feesamounts related to PECO’s meter reading operating lease. shared use land arrangements. |
| |
(d) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, PECO has excluded these payments from the remaining years as such amounts would not be meaningful. PECO’s average annual obligation for these arrangements, included in each of the years 2018-2022,2019 - 2023, was $5 million. Also includes amounts related to shared use land arrangements. |
| |
(d)(e) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs. |
| |
(e)(f) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(f)(g) | Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
BGE
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 2,600 |
| | $ | — |
| | $ | — |
| | $ | 550 |
| | $ | 2,050 |
| $ | 2,900 |
| | $ | — |
| | $ | 300 |
| | $ | 550 |
| | $ | 2,050 |
|
Interest payments on long-term debt(a) | 1,689 |
| | 101 |
| | 201 |
| | 186 |
| | 1,201 |
| 1,971 |
| | 113 |
| | 225 |
| | 191 |
| | 1,442 |
|
Operating leases(d)(e) | 170 |
| | 34 |
| | 68 |
| | 49 |
| | 19 |
| 143 |
| | 35 |
| | 68 |
| | 21 |
| | 19 |
|
Fuel purchase agreements(e)(f) | 514 |
| | 86 |
| | 121 |
| | 106 |
| | 201 |
| 434 |
| | 76 |
| | 107 |
| | 94 |
| | 157 |
|
Electric supply procurement(e)(f) | 1,026 |
| | 645 |
| | 381 |
| | — |
| | — |
| 1,070 |
| | 670 |
| | 400 |
| | — |
| | — |
|
Curtailment services commitments(e)(f) | 50 |
| | 22 |
| | 21 |
| | 7 |
| | — |
| 61 |
| | 10 |
| | 38 |
| | 13 |
| | — |
|
Other purchase obligations(f)(g) | 453 |
| | 394 |
| | 50 |
| | 4 |
| | 5 |
| 584 |
| | 528 |
| | 50 |
| | 2 |
| | 4 |
|
PJM regional transmission expansion commitments(g)(h) | 118 |
| | 35 |
| | 70 |
| | 13 |
| | — |
| 89 |
| | 35 |
| | 54 |
| | — |
| | — |
|
Total contractual obligations | $ | 6,620 |
| | $ | 1,317 |
|
| $ | 912 |
|
| $ | 915 |
|
| $ | 3,476 |
| $ | 7,252 |
| | $ | 1,467 |
|
| $ | 1,242 |
|
| $ | 871 |
|
| $ | 3,672 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, BGE has excluded these payments from the remaining years as such amounts would not be meaningful. BGE’s average annual obligation for these arrangements, included in each of the years 2018—2022,2019 - 2023, was $1 million, respectively.million. Also includes amounts related to shared use land arrangements. |
| |
(c)(d) | Includes all future lease payments on a 99-year real estate lease that expires in 2106. |
| |
(d)(e) | The BGE columntable above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $25 million, $26 million, $28 million, , $28 million, and $14 million related to years 2018, 2019 2020, 2021and- 2022, respectively. |
| |
(e)(f) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services. |
| |
(f)(g) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(g)(h) | Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. |
PHI
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 5,162 |
| | $ | 370 |
| | $ | 12 |
| | $ | 551 |
| | $ | 4,229 |
| $ | 5,622 |
| | $ | 111 |
| | $ | 281 |
| | $ | 810 |
| | $ | 4,420 |
|
Interest payments on long-term debt(a) | 1,328 |
| | 231 |
| | 461 |
| | 433 |
| | 203 |
| 4,192 |
| | 260 |
| | 512 |
| | 476 |
| | 2,944 |
|
Capital leases | 27 |
| | 13 |
| | 14 |
| | — |
| | — |
| 14 |
| | 14 |
| | — |
| | — |
| | — |
|
Operating leases(b) | 415 |
| | 56 |
| | 86 |
| | 79 |
| | 194 |
| 377 |
| | 48 |
| | 89 |
| | 81 |
| | 159 |
|
Fuel purchase agreements(b)(c) | 270 |
| | 30 |
| | 60 |
| | 60 |
| | 120 |
| 284 |
| | 30 |
| | 61 |
| | 64 |
| | 129 |
|
Long-term renewable energy and REC commitments(b)(c) | 345 |
| | 29 |
| | 58 |
| | 58 |
| | 200 |
| 341 |
| | 31 |
| | 62 |
| | 62 |
| | 186 |
|
Electric supply procurement(b)(c) | 1,720 |
| | 1,060 |
| | 660 |
| | — |
| | — |
| 1,635 |
| | 993 |
| | 642 |
| | — |
| | — |
|
Curtailment services commitments(b)(c) | 69 |
| | 30 |
| | 33 |
| | 6 |
| | — |
| 68 |
| | 19 |
| | 36 |
| | 13 |
| | — |
|
Other purchase obligations(c)(d) | 3,434 |
| | 2,368 |
| | 822 |
| | 196 |
| | 48 |
| 1,396 |
| | 893 |
| | 437 |
| | 34 |
| | 32 |
|
DC PLUG obligation(d)(e) | 188 |
| | 28 |
| | 60 |
| | 60 |
| | 40 |
| 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
PJM regional transmission expansion commitments(e)(f) | 234 |
| | 92 |
| | 67 |
| | 75 |
| | — |
| 77 |
| | 39 |
| | 29 |
| | 9 |
| | — |
|
Total contractual obligations | $ | 13,192 |
| | $ | 4,307 |
| | $ | 2,333 |
| | $ | 1,518 |
| | $ | 5,034 |
| $ | 14,166 |
| | $ | 2,468 |
| | $ | 2,209 |
| | $ | 1,609 |
| | $ | 7,880 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services. |
| |
(c)(d) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(d)(e) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 34 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e)(f) | Under its operating agreement with PJM, PHI is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PHI’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. |
Pepco
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 2,543 |
| | $ | 6 |
| | $ | — |
| | $ | 312 |
| | $ | 2,225 |
| $ | 2,737 |
| | $ | 1 |
| | $ | 1 |
| | $ | 310 |
| | $ | 2,425 |
|
Interest payments on long-term debt(a) | 755 |
| | 129 |
| | 259 |
| | 251 |
| | 116 |
| 2,488 |
| | 138 |
| | 276 |
| | 256 |
| | 1,818 |
|
Capital leases | 27 |
| | 13 |
| | 14 |
| | — |
| | — |
| 14 |
| | 14 |
| | — |
| | — |
| | — |
|
Operating leases(b) | 38 |
| | 8 |
| | 13 |
| | 9 |
| | 8 |
| 86 |
| | 11 |
| | 19 |
| | 16 |
| | 40 |
|
Electric supply procurement(b)(c) | 675 |
| | 433 |
| | 242 |
| | — |
| | — |
| 663 |
| | 407 |
| | 256 |
| | — |
| | — |
|
Curtailment services commitments(b)(c) | 26 |
| | 13 |
| | 10 |
| | 3 |
| | — |
| 33 |
| | 4 |
| | 20 |
| | 9 |
| | — |
|
Other purchase obligations(c)(d) | 1,676 |
| | 995 |
| | 497 |
| | 146 |
| | 38 |
| 908 |
| | 509 |
| | 337 |
| | 31 |
| | 31 |
|
DC PLUG obligation(d)(e) | 188 |
| | 28 |
| | 60 |
| | 60 |
| | 40 |
| 160 |
| | 30 |
| | 60 |
| | 60 |
| | 10 |
|
PJM regional transmission expansion commitments(e) | 86 |
| | 5 |
| | 38 |
| | 43 |
| | — |
| |
Total contractual obligations | $ | 6,014 |
| | $ | 1,630 |
| | $ | 1,133 |
| | $ | 824 |
| | $ | 2,427 |
| $ | 7,089 |
| | $ | 1,114 |
| | $ | 969 |
| | $ | 682 |
| | $ | 4,324 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to purchase procure electric supply and curtailment services. |
| |
(c)(d) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(d)(e) | Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover this charge from customers through a volumetric distribution rider. See Note 34 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information. |
| |
(e) | Under its operating agreement with PJM, Pepco is committed to the construction of transmission facilities to maintain system reliability. These amounts represent Pepco’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. |
DPL
| | | | | Payment due within | | | | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond | Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 1,309 |
| | $ | 83 |
| | $ | 12 |
| | $ | — |
| | $ | 1,214 |
| $ | 1,504 |
| | $ | 91 |
| | $ | — |
| | $ | 500 |
| | $ | 913 |
|
Interest payments on long-term debt(a) | 288 |
| | 49 |
| | 97 |
| | 96 |
| | 46 |
| 1,050 |
| | 57 |
| | 113 |
| | 111 |
| | 769 |
|
Operating leases(b) | 121 |
| | 20 |
| | 23 |
| | 24 |
| | 54 |
| 96 |
| | 14 |
| | 25 |
| | 22 |
| | 35 |
|
Fuel purchase agreements(c) | 270 |
| | 30 |
| | 60 |
| | 60 |
| | 120 |
| 284 |
| | 30 |
| | 61 |
| | 64 |
| | 129 |
|
Long-term renewable energy and associated REC commitments(c) | 345 |
| | 29 |
| | 58 |
| | 58 |
| | 200 |
| 341 |
| | 31 |
| | 62 |
| | 62 |
| | 186 |
|
Electric supply procurement(c) | 504 |
| | 312 |
| | 192 |
| | — |
| | — |
| 458 |
| | 282 |
| | 176 |
| | — |
| | — |
|
Curtailment services commitments(c) | 36 |
| | 14 |
| | 19 |
| | 3 |
| | — |
| 31 |
| | 12 |
| | 15 |
| | 4 |
| | — |
|
Other purchase obligations(d) | 963 |
| | 776 |
| | 152 |
| | 32 |
| | 3 |
| 266 |
| | 187 |
| | 77 |
| | 1 |
| | 1 |
|
PJM regional transmission expansion commitments(e) | 27 |
| | 19 |
| | 3 |
| | 5 |
| | — |
| 9 |
| | 3 |
| | 3 |
| | 3 |
| | — |
|
Total contractual obligations | $ | 3,863 |
| | $ | 1,332 |
| | $ | 616 |
| | $ | 278 |
| | $ | 1,637 |
| $ | 4,039 |
| | $ | 707 |
| | $ | 532 |
| | $ | 767 |
| | $ | 2,033 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 20172018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | AmountsIncludes amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, DPL has excluded these payments from the remaining years as such amounts would not be meaningful. DPL's average annual obligation for these arrangements, included in each of the years 2018-2022, was $2 million.shared use land arrangements. |
| |
(c) | Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric supply, and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 20172018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s expected portion of the costs to pay for the completion of the required construction projects. |
ACE
|
| | | | | | | | | | | | | | | | | | | |
| | | Payment due within | | |
| Total | | 2019 | | 2020 - 2021 | | 2022 - 2023 | | Due 2024 and beyond |
Long-term debt | $ | 1,196 |
| | $ | 18 |
| | $ | 280 |
| | $ | — |
| | $ | 898 |
|
Interest payments on long-term debt (a) | 465 |
| | 52 |
| | 95 |
| | 81 |
| | 237 |
|
Operating leases(b) | 32 |
| | 7 |
| | 11 |
| | 9 |
| | 5 |
|
Electric supply procurement (c) | 514 |
| | 304 |
| | 210 |
| | — |
| | — |
|
Curtailment services commitments (c) | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
|
Other purchase obligations (d) | 177 |
| | 160 |
| | 16 |
| | 1 |
| | — |
|
PJM regional transmission expansion commitments (e) | 68 |
| | 36 |
| | 26 |
| | 6 |
| | — |
|
Total contractual obligations | $ | 2,456 |
| | $ | 580 |
| | $ | 639 |
| | $ | 97 |
| | $ | 1,140 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Includes amounts related to shared use land arrangements. |
| |
(c) | Represents commitments to procure electric supply and curtailment services. |
| |
(d) | Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(e) | Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. |
ACE
|
| | | | | | | | | | | | | | | | | | | |
| | | Payment due within | | |
| Total | | 2018 | | 2019 - 2020 | | 2021 - 2022 | | Due 2023 and beyond |
Long-term debt | $ | 1,127 |
| | $ | 281 |
| | $ | — |
| | $ | 239 |
| | $ | 607 |
|
Interest payments on long-term debt (a) | 201 |
| | 39 |
| | 77 |
| | 58 |
| | 27 |
|
Operating leases | 57 |
| | 9 |
| | 16 |
| | 13 |
| | 19 |
|
Electric supply procurement (b) | 541 |
| | 315 |
| | 226 |
| | — |
| | — |
|
Curtailment services commitments (b) | 7 |
| | 3 |
| | 4 |
| | — |
| | — |
|
Other purchase obligations (c) | 581 |
| | 439 |
| | 124 |
| | 15 |
| | 3 |
|
PJM regional transmission expansion commitments (d) | 121 |
| | 68 |
| | 26 |
| | 27 |
| | — |
|
Total contractual obligations | $ | 2,635 |
| | $ | 1,154 |
| | $ | 473 |
| | $ | 352 |
| | $ | 656 |
|
__________
| |
(a) | Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2017 and do not reflect anticipated future refinancing, early redemptions or debt issuances. |
| |
(b) | Represents commitments to procure electric supply and curtailment services. |
| |
(c) | Represents the future estimated value at December 31, 2017 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period. |
| |
(d) | Under its operating agreement with PJM, ACE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ACE’s expected portion of the costs to pay for the completion of the required construction projects. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. |
See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for discussionadditional information of the Registrants’ other commitments potentially triggered by future events.
For additional information regarding:
commercial paper, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
long-term debt, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
liabilities related to uncertain tax positions, see Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements.
capital lease obligations, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
operating leases and rate relief commitments, see Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
the nuclear decommissioning and SNF obligations, see NotesNote 15 — Asset Retirement Obligations and 23Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
regulatory commitments, see Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
variable interest entities, see Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.
nuclear insurance, see Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
new accounting pronouncements, see Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements.
|
| |
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel and other commodities.
Generation
Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20182019 through 2020.2021.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation, typically on a ratable basis over three-year periods. As of December 31, 2017,2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 85%-88%89%-92%, 55%-58%56%-59% and 26%-29%32%-35% for 2018, 2019, 2020 and 2020,
2021, 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, which include economic hedges and certain non-derivative contracts, including Generation’s sales to ComEd, PECO and BGE to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on December 31, 20172018 market conditions and hedged position would be decreases in pre-tax net income of approximately $110$57 million, $400$383 million and $630$618 million, respectively, for 2018, 2019, 2020 and 2020.2021. Power price sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to mitigate market price risk exposure for its unhedged position. Actual
results could differ depending on the specific timing of, and markets affected by, price changes, as well as future changes in Generation’s portfolio. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Proprietary Trading Activities
Proprietary trading portfolio activity for the year ended December 31, 2017,2018, resulted in pre-tax gains of $18$42 million due to net mark-to-market gains of $5$17 million and realized gains of $13$25 million. Generation has not segregated proprietary trading activity within the following discussion because of the relative size of the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchased power and fuel expense. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Generation procures natural gas through long-term and short-term contracts, and spot-market purchases. Nuclear fuel assemblies are obtained predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 59%62% of Generation’s uranium concentrate requirements from 20182019 through 20222023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.statements.
ComEd
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The 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.
ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. The block energy contracts are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. ComEd does not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
PECO, BGE, Pepco, DPL and ACE
PECO, BGE, Pepco, DPL and ACE have contracts to procure electric supply that are executed through a competitive procurement process, which are further discussed in Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO, BGE, Pepco, DPL and ACE have certain full requirements contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE and DPL have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception or have no mark-to-market balances because the derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct impact on their results of operations or financial position.statements.
PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities
The following tables detailtable detailing Exelon’s, Generation’s ComEd’s, PHI's and DPL'sComEd’s trading and non-trading marketing activities isare included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s ComEd’s, PHI's and DPL'sComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 20152016 to December 31, 2017.2018. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 20172018 and 2016.
2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | Predecessor |
| | | | | | | | | March 24 to December 31, | | | January 1 to March 23, |
| Exelon | | Generation | | ComEd | | DPL | | PHI | | | PHI |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2015(a) | $ | 1,506 |
|
| $ | 1,753 |
| | $ | (247 | ) | | $ | — |
| | $ | — |
| | | $ | — |
|
Total change in fair value during 2016 of contracts recorded in result of operations | 236 |
| | 236 |
| | — |
| | — |
| | | | | — |
|
Reclassification to be realized at settlement of contracts recorded in results of operations | (265 | ) | | (265 | ) | | — |
| | — |
| | — |
| | | — |
|
Contracts received at acquisition date(b) | (59 | ) | | (59 | ) | | — |
| | — |
| | — |
| | | — |
|
Changes in fair value—recorded through regulatory assets and liabilities(c) | (8 | ) | | — |
| | (11 | ) | | 4 |
| | 3 |
| | | 1 |
|
Changes in allocated collateral | (908 | ) | | (905 | ) | | — |
| | (4 | ) | | (3 | ) | | | (1 | ) |
Changes in net option premium paid | 66 |
| | 66 |
| | — |
| | — |
| | — |
| | | — |
|
Option premium amortization | 11 |
| | 11 |
| | — |
| | — |
| | — |
| | | — |
|
Upfront payments and amortizations(d) | 140 |
| | 140 |
| | — |
| | — |
| | | | | |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 |
| | $ | 977 |
| | $ | (258 | ) | | $ | — |
| | $ | — |
| | | $ | — |
|
|
| | | | | | | | | | | |
| Exelon | | Generation | | ComEd |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 |
|
| $ | 977 |
| | $ | (258 | ) |
Total change in fair value during 2017 of contracts recorded in result of operations | 110 |
| | 110 |
| | — |
|
Reclassification to realized at settlement of contracts recorded in results of operations | (273 | ) | | (273 | ) | | — |
|
Changes in fair value—recorded through regulatory assets and liabilities(b) | (1 | ) | | — |
| | 2 |
|
Changes in allocated collateral | 140 |
| | 137 |
| | — |
|
Net option premium received | (28 | ) | | (28 | ) | | — |
|
Option premium amortization | (7 | ) | | (7 | ) | | — |
|
Upfront payments and amortizations(c) | (24 | ) | | (24 | ) | | — |
|
Other miscellaneous(d) | 31 |
| | 31 |
| | — |
|
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a) | 667 |
| | 923 |
| | (256 | ) |
Total change in fair value during 2018 of contracts recorded in result of operations | 270 |
| | 270 |
| | — |
|
Reclassification to realized at settlement of contracts recorded in results of operations | (570 | ) | | (570 | ) | | — |
|
Contracts received at acquisition date(e) | (19 | ) | | (19 | ) | | — |
|
Changes in fair value—recorded through regulatory assets and liabilities(b) | 8 |
| | — |
| | 7 |
|
Changes in allocated collateral | (110 | ) | | (109 | ) | | — |
|
Net option premium paid | 43 |
| | 43 |
| | — |
|
Option premium amortization | (10 | ) | | (10 | ) | | — |
|
Upfront payments and amortizations(c) | 20 |
| | 20 |
| | — |
|
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a) | $ | 299 |
| | $ | 548 |
| | $ | (249 | ) |
__________
| |
(a) | Amounts are shown net of collateral paid to and received from counterparties. |
| |
(b) | Includes fair value from contracts received at acquisition of ConEdison Solutions of $(59) million. |
| |
(c) | For ComEd, and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2016,2017 and 2018, ComEd recorded a regulatory liability of $258$256 million and $249 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $29$18 million of decreases in fair value and an increase for realized losses due to settlements of $18$20 million in purchased power expense associated with floating-to-fixed energy swap suppliers for the year ended December 31, 2016. |
| |
(d) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts2017. ComEd recorded $24 million of cash, excluding option premiums, and the associated amortizations.decreases in fair value |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor |
| Exelon | | Generation | | ComEd | | DPL | | PHI |
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016(a) | $ | 719 |
| | $ | 977 |
| | $ | (258 | ) | | $ | — |
| | $ | — |
|
Total change in fair value during 2016 of contracts recorded in result of operations | 110 |
| | 110 |
| | — |
| | — |
| | — |
|
Reclassification to be realized at settlement of contracts recorded in results of operations | (273 | ) | | (273 | ) | | — |
| | — |
| | — |
|
Changes in fair value—recorded through regulatory assets and liabilities(c) | (1 | ) | | — |
| | 2 |
| | (3 | ) | | (3 | ) |
Changes in allocated collateral | 140 |
| | 137 |
| | — |
| | 3 |
| | 3 |
|
Changes in net option premium received | (28 | ) | | (28 | ) | | — |
| | — |
| | — |
|
Option premium amortization | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
|
Upfront payments and amortizations(b) | (24 | ) | | (24 | ) | | — |
| | — |
| | — |
|
Other miscellaneous(d) | 31 |
| | 31 |
| | — |
| | — |
| | — |
|
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a) | $ | 667 |
| | $ | 923 |
| | $ | (256 | ) | | $ | — |
| | $ | — |
|
__________and realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018.
| |
(a) | Amounts are shown net of collateral paid to and received from counterparties. |
| |
(b)(c) | Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations. |
| |
(c) | For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2017, ComEd recorded a regulatory liability of $256 million, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the year ended December 31, 2017, ComEd also recorded $18 million of decreases in fair value and realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017. |
| |
(d) | As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon’sExelon's and GenerationGeneration's consolidated financial statements. |
| |
(e) | Includes fair value from contracts received at acquisition of the Everett Marine Terminal. |
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities) net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 11 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.
Exelon
| | | Maturities Within | | Total Fair Value | Maturities Within | | Total Fair Value |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and Beyond | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | | | | | | | | | | | | | |
Actively quoted prices (Level 1) | $ | (32 | ) | | $ | (43 | ) | | $ | (15 | ) | | $ | 2 |
| | $ | (2 | ) | | $ | — |
| | $ | (90 | ) | $ | (11 | ) | | $ | (33 | ) | | $ | (6 | ) | | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | (44 | ) |
Prices provided by external sources (Level 2) | 462 |
| | (6 | ) | | (1 | ) | | 6 |
| | — |
| | — |
| | 461 |
| 45 |
| | (33 | ) | | 5 |
| | — |
| | — |
| | — |
| | 17 |
|
Prices based on model or other valuation methods (Level 3)(c) | 315 |
| | 130 |
| | 23 |
| | (27 | ) | | (58 | ) | | (87 | ) | | 296 |
| 291 |
| | 174 |
| | — |
| | (63 | ) | | (23 | ) | | (53 | ) | | 326 |
|
Total | $ | 745 |
| | $ | 81 |
| | $ | 7 |
| | $ | (19 | ) | | $ | (60 | ) | | $ | (87 | ) | | $ | 667 |
| $ | 325 |
| | $ | 108 |
| | $ | (1 | ) | | $ | (71 | ) | | $ | (9 | ) | | $ | (53 | ) | | $ | 299 |
|
__________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466$357 million at December 31, 2017.2018. |
| |
(c) | Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Generation
| | | Maturities Within | | Total Fair Value | Maturities Within | | Total Fair Value |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and Beyond | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | |
Normal Operations, Commodity derivative contracts(a)(b): | | | | | | | | | | | | | | | | | | | | | | | | | | |
Actively quoted prices (Level 1) | $ | (32 | ) | | $ | (43 | ) | | $ | (15 | ) | | $ | 2 |
| | $ | (2 | ) | | $ | — |
| | $ | (90 | ) | $ | (11 | ) | | $ | (33 | ) | | $ | (6 | ) | | $ | (8 | ) | | $ | 14 |
| | $ | — |
| | $ | (44 | ) |
Prices provided by external sources (Level 2) | 462 |
| | (6 | ) | | (1 | ) | | 6 |
| | — |
| | — |
| | 461 |
| 45 |
| | (33 | ) | | 5 |
| | — |
| | — |
| | — |
| | 17 |
|
Prices based on model or other valuation methods (Level 3)(c) | 336 |
| | 152 |
| | 44 |
| | (6 | ) | | (37 | ) | | 63 |
| | 552 |
| 317 |
| | 199 |
| | 25 |
| | (37 | ) | | 3 |
| | 68 |
| | 575 |
|
Total | $ | 766 |
| | $ | 103 |
| | $ | 28 |
| | $ | 2 |
| | $ | (39 | ) | | $ | 63 |
| | $ | 923 |
| $ | 351 |
| | $ | 133 |
| | $ | 24 |
| | $ | (45 | ) | | $ | 17 |
| | $ | 68 |
| | $ | 548 |
|
__________
| |
(a) | Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations. |
| |
(b) | Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $466$357 million at December 31, 2017.2018. |
ComEd
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Fair Value |
| 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and Beyond | |
Prices based on model or other valuation methods (Level 3)(a) | $ | (21 | ) | | $ | (22 | ) | | $ | (21 | ) | | $ | (21 | ) | | $ | (21 | ) | | $ | (150 | ) | | $ | (256 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Maturities Within | | Fair Value |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and Beyond | |
Prices based on model or other valuation methods (Level 3)(a) | $ | (26 | ) | | $ | (25 | ) | | $ | (25 | ) | | $ | (26 | ) | | $ | (26 | ) | | $ | (121 | ) | | $ | (249 | ) |
__________
| |
(a) | Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Credit Risk, Collateral and Contingent Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12—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 purchases and normal sales agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2017.2018. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $28$43 million, $22$30 million, $24 million, $36$28 million, $12$7 million and $6$5 million respectively. See Note 2625 — Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.
| | Rating as of December 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 | |
Rating as of December 31, 2018 | | Total Exposure Before Credit Collateral | | Credit Collateral (a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure |
Investment grade | $ | 738 |
| | $ | 4 |
| | $ | 734 |
| | 1 |
| | $ | 244 |
| $ | 795 |
| | $ | — |
| | $ | 795 |
| | 1 |
| | $ | 153 |
|
Non-investment grade | 90 |
| | 12 |
| | 78 |
| | — |
| | — |
| 133 |
| | 45 |
| | 88 |
| | — |
| | — |
|
No external ratings | | | | | | | | | | | | | | | | | | |
Internally rated—investment grade | 253 |
| | — |
| | 253 |
| | — |
| | — |
| 181 |
| | 1 |
| | 180 |
| | — |
| | — |
|
Internally rated—non-investment grade | 83 |
| | 11 |
| | 72 |
| | — |
| | — |
| 92 |
| | 6 |
| | 86 |
| | — |
| | — |
|
Total | $ | 1,164 |
| | $ | 27 |
| | $ | 1,137 |
| | 1 |
| | $ | 244 |
| $ | 1,201 |
| | $ | 52 |
| | $ | 1,149 |
| | 1 |
| | $ | 153 |
|
| | | Maturity of Credit Risk Exposure | Maturity of Credit Risk Exposure |
Rating as of December 31, 2017 | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral | |
Rating as of December 31, 2018 | | Less than 2 Years | | 2-5 Years | | Exposure Greater than 5 Years | | Total Exposure Before Credit Collateral |
Investment grade | $ | 657 |
| | $ | 80 |
| | $ | 1 |
| | $ | 738 |
| $ | 755 |
| | $ | 23 |
| | $ | 17 |
| | $ | 795 |
|
Non-investment grade | 74 |
| | 16 |
| | — |
| | 90 |
| 131 |
| | 2 |
| | — |
| | 133 |
|
No external ratings | | | | | | | | | | | | | | |
Internally rated—investment grade | 191 |
| | 30 |
| | 32 |
| | 253 |
| 126 |
| | 26 |
| | 29 |
| | 181 |
|
Internally rated—non-investment grade | 79 |
| | 4 |
| | — |
| | 83 |
| 82 |
| | 5 |
| | 5 |
| | 92 |
|
Total | $ | 1,001 |
| | $ | 130 |
| | $ | 33 |
| | $ | 1,164 |
| $ | 1,094 |
| | $ | 56 |
| | $ | 51 |
| | $ | 1,201 |
|
| | Net Credit Exposure by Type of Counterparty | As of December 31, 2017 | As of December 31, 2018 |
Financial institutions | $ | 41 |
| $ | 12 |
|
Investor-owned utilities, marketers, power producers | 558 |
| 737 |
|
Energy cooperatives and municipalities | 452 |
| 324 |
|
Other | 86 |
| 76 |
|
Total | $ | 1,137 |
| $ | 1,149 |
|
__________
| |
(a) | As of December 31, 2017,2018, credit collateral held from counterparties where Generation had credit exposure included $8$17 million of cash and $19$35 million of letters of credit. |
The Utility Registrants
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record a provision for uncollectible accounts, based upon historical experience, to provide for the potential loss from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the provision for uncollectible accounts. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of December 31, 2017.2018. See Note 34 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
As of December 31, 2017, ComEd’s2018, ComEd, PECO, BGE, Pepco, DPL and ACE's net credit exposure to suppliers was approximately $1 million. PECO and BGE had no net credit exposure to suppliers as of December 31, 2017. As of December 31, 2017 Pepco, DPL and ACE's net credit exposures were immaterial. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
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. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation
at the time of the demand. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 2322 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these
payments from counterparties could have a material impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 7.Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities for additional information.
The Utility Registrants
As of December 31, 2017,2018, ComEd held $10$38 million in collateral from suppliers in association with energy procurement contracts, approximately $2$31 million in collateral from suppliers for REC contract obligations and approximately $19 million in collateral from suppliers for long-term renewable energy contracts. BGE is not required to post collateral under its electric supply contracts but was holding an immaterial amount of collateral under its electric supply procurement contracts. BGE was not required to post collateral under its natural gas procurement contracts, but was holding an immaterial amount of collateral under its natural gas procurement contracts. PECO, Pepco and DPL were not required to post collateral under their energy and/or natural gas procurement contracts, but were holding an immaterial amount of collateral under their respective electric supply procurement contracts. PECO and ACE were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 34 — Regulatory Matters and Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a material adverse impact on the Registrants’ results of operations, cash flows and financial positions.statements.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps which are typically designated as fair value hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2017,2018, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $636$622 million of notional amounts of floating-to-fixed hedges outstanding. Assuming the fair value and cash flow interest rate hedges are 100% effective, aA hypothetical 50 basis point increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $6 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2017.2018. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 12—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of December 31, 2017,2018, Generation’s decommissioning trustNDT funds are reflected at fair value onin 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 $662$529 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 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussionadditional information of equity price risk as a result of the current capital and credit market conditions.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Generation
General
Generation’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable energy and other energy-related products and services. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of Generation’s results of operations for 2018 compared to 2017 and 2017 compared to 2016 and 2016 compared to 2015 is set forth under Results of Operations—Generation in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, participation in the intercompany money pool or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where Generation no longer has access to the capital markets at reasonable terms, Generation has access to credit facilities in the aggregate of $5.8$5.3 billion that Generation currently utilizes to support its commercial paper program and to issueissuances of letters of credit.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund Generation’s capital requirements, including construction retirement ofexpenditures, retire debt, the payment of distributions to Exelon, contributions to Exelon’spay dividends, fund pension plans and investmentsother postretirement benefit obligations and invest in new and existing ventures. Future acquisitions could require external financing or borrowings orGeneration spends a significant amount of cash on capital contributions from Exelon.
improvements and construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Generation’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Generation
Generation is exposed to market risks associated with commodity price, credit, interest rates and equity price. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ComEd
General
ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM 1. BUSINESS—ComEd of this Form 10-K.
Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of ComEd’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—ComEd in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2017,2018, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ComEd spends a significant amount of debt,cash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ComEd’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ComEd
ComEd is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PECO
General
PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail in ITEM 1. BUSINESS—PECO of this Form 10-K.
Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of PECO’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—PECO in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or participation in the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable terms, PECO has access to a revolving credit facility. At December 31, 2017,2018, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund PECO’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. PECO spends a significant amount of debt, the payment of dividendscash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PECO’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PECO
PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
BGE
General
BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form 10-K.
Executive Overview
A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of BGE’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—BGE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
BGE’s business is capital intensive and requires considerable capital resources. BGE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. BGE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At December 31, 2017,2018, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund BGE’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. BGE spends a significant amount of debt, the payment of dividendscash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, BGE operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to BGE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to BGE’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to BGE’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to BGE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of BGE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of BGE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
BGE
BGE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
PHI
General
PHI has three reportable segments Pepco, DPL, and ACE. Its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.
Executive Overview
A discussion of items pertinent to PHI’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Successor Period Year Ended December 31, 2018 Compared to Year Ended December 31, 2017, Successor Period of March 24, 2016 to December 31, 2016 and Predecessor Period of January 1, 2016 to March 23, 2016 Predecessor Period Year Ended December 31, 2015
A discussion of PHI’s results of operations for 20172018 compared to 2016,2017, March 24, 2016 to December 31, 2016 and January 1, 2016 to March 23, 2016 and the year ended December 31, 2015 is set forth under Results of Operations—PHI in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PHI’s business is capital intensive and requires considerable capital resources. PHI’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper, borrowings from the Exelon money pool or capital contributions from Exelon. PHI’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund PHI’s capital requirements, including construction retirement ofexpenditures, retire debt, the payment ofpay dividends, fund pension and contributions to Exelon’s pension plans. Additionally,other postretirement benefit obligations and invest in new and existing ventures. PHI operates inspends a rate-regulated environment in which thesignificant amount of new investment recovery may be limitedcash on capital improvements and where such recovery takes place over an extended period of time.construction projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to PHI’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PHI’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PHI’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PHI’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
PHI
PHI is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk — Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
Pepco
General
Pepco operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.
Executive Overview
A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of Pepco’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—Pepco in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Pepco’s business is capital intensive and requires considerable capital resources. Pepco’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2017,2018, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund Pepco’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. Pepco spends a significant amount of debt,cash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, Pepco operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Pepco’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
Pepco
Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
DPL
General
DPL operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas in New Castle County, Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K.
Executive Overview
A discussion of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of DPL’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—DPL in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
DPL’s business is capital intensive and requires considerable capital resources. DPL’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where DPL no longer has access to the capital markets at reasonable terms, DPL has access to a revolving credit facility. At December 31, 2017,2018, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund DPL’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. DPL spends a significant amount of debt, the payment of dividendscash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to DPL’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of DPL’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
DPL
DPL is exposed to market risks associated with commodity price, credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk—Exelon.
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ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
ACE
General
ACE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE of this Form 10-K.
Executive Overview
A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 and Year Ended December 31, 2016 Compared to Year Ended December 31, 2015
A discussion of ACE’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 and for 2016 compared to 2015 is set forth under Results of Operations—ACE in EXELON CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper or credit facility borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. At December 31, 2017,2018, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements of this Form 10-K for further discussion.additional information.
Capital resources are used primarily to fund ACE’s capital requirements, including construction retirementexpenditures, retire debt, pay dividends, fund pension and other postretirement benefit obligations and invest in new and existing ventures. ACE spends a significant amount of debt,cash on capital improvements and contributions to Exelon’s pension plans.construction projects that have a long-term return on investment. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ACE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ACE’s contractual obligations, commercial commitments and off-balance sheet arrangements is set forth under Contractual Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting pronouncements.
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ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
ACE
ACE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures about Market Risk— Exelon.
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ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2017,2018, Exelon’s internal control over financial reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2017,2018, Generation’s internal control over financial reporting was effective.
The effectiveness of Generation’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2017,2018, ComEd’s internal control over financial reporting was effective.
The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PECO’s management concluded that, as of December 31, 2017,2018, PECO’s internal control over financial reporting was effective.
The effectiveness of PECO’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2017,2018, BGE’s internal control over financial reporting was effective.
The effectiveness of BGE’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Pepco Holdings LLC (PHI) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
PHI’s management conducted an assessment of the effectiveness of PHI’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, PHI’s management concluded that, as of December 31, 2017,2018, PHI’s internal control over financial reporting was effective.
The effectiveness of PHI’s internal control over financial reporting as of December 31, 2017,2018, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Pepco’s management concluded that, as of December 31, 2017,2018, Pepco’s internal control over financial reporting was effective.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, DPL’s management concluded that, as of December 31, 2017,2018, DPL’s internal control over financial reporting was effective.
February 9, 20188, 2019
Management’s Report on Internal Control Over Financial Reporting
The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2017.2018. In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, ACE’s management concluded that, as of December 31, 2017,2018, ACE’s internal control over financial reporting was effective.
February 9, 20188, 2019
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Exelon Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial statement schedules listed in the index appearing under Item 15(a)(2)(1)(ii), of Exelon Corporation and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 9, 20188, 2019
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Exelon Generation Company, LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(2)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Exelon Generation Company, LLC and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 9, 20188, 2019
We have served as the Company’s auditor since 2001.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Commonwealth Edison Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(3)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(3)(ii), of Commonwealth Edison Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 9, 20188, 2019
We have served as the Company’s auditor since 2000.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of PECO Energy Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(4)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(4)(ii), of PECO Energy Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 9, 20188, 2019
We have served as the Company’s auditor since 1932.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Baltimore Gas and Electric Company
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(5)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(5)(ii), of Baltimore Gas and Electric Company and its subsidiaries (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 9, 20188, 2019
We have served as the Company’s auditor since at least 1993. We have not determinedbeen able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Pepco Holdings LLC
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(6)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(6)(iii), of Pepco Holdings LLC and its subsidiaries (Successor) (the "Company") (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 20162017, and the results of theirits operations and theirits cash flows for each of the yeartwo years in the period ended December 31, 2017,2018 and for the period from March 24, 2016 to December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017,2018, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB")(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.DC
February 9, 20188, 2019
We have served as the Company’s auditor since 2001.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Pepco Holdings LLC
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1)(6)(ii) present fairly, in all material respects, the results of operations and the cash flows of Pepco Holdings LLC and its subsidiaries (formerly Pepco Holdings, Inc.) (Predecessor) for the period January 1, 2016 to March 23, 2016 and for the year ended December 31, 2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for the period January 1, 2016 to March 23, 2016 listed in the index appearing under Item 15(a)(2)(6)(iv) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based on our audits.audit. We conducted our auditsaudit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provideaudit provides a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for interest on uncertain tax positions in 2016.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.DC
February 13, 2017
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(7)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(7)(ii), of Potomac Electric Power Company (the "Company") (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.DC
February 9, 20188, 2019
We have served as the Company's auditor since at least 1993. We have not determinedbeen able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(8)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(8)(ii), of Delmarva Power & Light Company (the "Company") (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.DC
February 9, 20188, 2019
We have served as the Company's auditor since at least 1993. We have not determinedbeen able to determine the specific year we began serving as auditor of the Company.
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(9)(i), and the financial statement schedule listed in the index appearing under Item 15(a)(2)(9)(ii), of Atlantic City Electric Company and its subsidiary (the "Company") (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 20172018 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”)(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.DC
February 9, 20188, 2019
We have served as the Company's auditor since 1998.
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive IncomeIncome | | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions, except per share data) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Competitive businesses revenues | $ | 17,360 |
| | $ | 16,324 |
| | $ | 18,395 |
| $ | 19,168 |
| | $ | 17,394 |
| | $ | 16,330 |
|
Rate-regulated utility revenues | 16,171 |
| | 15,036 |
| | 11,052 |
| 16,879 |
| | 15,964 |
| | 14,988 |
|
Revenues from alternative revenue programs | | (62 | ) | | 207 |
| | 48 |
|
Total operating revenues | 33,531 |
| | 31,360 |
| | 29,447 |
| 35,985 |
| | 33,565 |
| | 31,366 |
|
Operating expenses | | | | | | | | | | |
Competitive businesses purchased power and fuel | 9,668 |
| | 8,817 |
| | 10,007 |
| 11,679 |
| | 9,668 |
| | 8,817 |
|
Rate-regulated utility purchased power and fuel | 4,367 |
| | 3,823 |
| | 3,077 |
| 4,991 |
| | 4,367 |
| | 3,823 |
|
Operating and maintenance | 10,126 |
| | 10,048 |
| | 8,322 |
| 9,337 |
| | 10,025 |
| | 9,954 |
|
Depreciation and amortization | 3,828 |
| | 3,936 |
| | 2,450 |
| 4,353 |
| | 3,828 |
| | 3,936 |
|
Taxes other than income | 1,731 |
| | 1,576 |
| | 1,200 |
| 1,783 |
| | 1,731 |
| | 1,576 |
|
Total operating expenses | 29,720 |
|
| 28,200 |
|
| 25,056 |
| 32,143 |
|
| 29,619 |
|
| 28,106 |
|
Gain (Loss) on sales of assets | 3 |
| | (48 | ) | | 18 |
| |
Gain (loss) on sales of assets and businesses | | 56 |
| | 3 |
| | (48 | ) |
Bargain purchase gain | 233 |
| | — |
| | — |
| — |
| | 233 |
| | — |
|
Gain on deconsolidation of business | 213 |
| | — |
| | — |
| — |
| | 213 |
| | — |
|
Operating income | 4,260 |
|
| 3,112 |
|
| 4,409 |
| 3,898 |
|
| 4,395 |
|
| 3,212 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (1,524 | ) | | (1,495 | ) | | (992 | ) | (1,529 | ) | | (1,524 | ) | | (1,495 | ) |
Interest expense to affiliates | (36 | ) | | (41 | ) | | (41 | ) | (25 | ) | | (36 | ) | | (41 | ) |
Other, net | 1,056 |
| | 413 |
| | (46 | ) | (112 | ) | | 947 |
| | 297 |
|
Total other income and (deductions) | (504 | ) |
| (1,123 | ) |
| (1,079 | ) | (1,666 | ) |
| (613 | ) |
| (1,239 | ) |
Income before income taxes | 3,756 |
| | 1,989 |
| | 3,330 |
| 2,232 |
| | 3,782 |
| | 1,973 |
|
Income taxes | (125 | ) | | 761 |
| | 1,073 |
| 120 |
| | (126 | ) | | 753 |
|
Equity in losses of unconsolidated affiliates | (32 | ) | | (24 | ) | | (7 | ) | (28 | ) | | (32 | ) | | (24 | ) |
Net income | 3,849 |
|
| 1,204 |
|
| 2,250 |
| 2,084 |
|
| 3,876 |
|
| 1,196 |
|
Net income (loss) attributable to noncontrolling interests and preference stock dividends | 79 |
| | 70 |
| | (19 | ) | |
Net income attributable to noncontrolling interests and preference stock dividends | | 74 |
| | 90 |
| | 75 |
|
Net income attributable to common shareholders | $ | 3,770 |
|
| $ | 1,134 |
|
| $ | 2,269 |
| $ | 2,010 |
|
| $ | 3,786 |
|
| $ | 1,121 |
|
Comprehensive income, net of income taxes | | | | | | | | | | |
Net income | $ | 3,849 |
| | $ | 1,204 |
| | $ | 2,250 |
| $ | 2,084 |
| | $ | 3,876 |
| | $ | 1,196 |
|
Other comprehensive income (loss), net of income taxes | | | | | | | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | | | | |
Prior service benefit reclassified to periodic benefit cost | (56 | ) | | (48 | ) | | (46 | ) | (66 | ) | | (56 | ) | | (48 | ) |
Actuarial loss reclassified to periodic benefit cost | 197 |
| | 184 |
| | 220 |
| 247 |
| | 197 |
| | 184 |
|
Pension and non-pension postretirement benefit plan valuation adjustment | 10 |
| | (181 | ) | | (99 | ) | (143 | ) | | 10 |
| | (181 | ) |
Unrealized gain on cash flow hedges | 3 |
| | 2 |
| | 9 |
| 12 |
| | 3 |
| | 2 |
|
Unrealized gain on marketable securities | 6 |
| | 1 |
| | — |
| — |
| | 6 |
| | 1 |
|
Unrealized gain (loss) on equity investments | 4 |
| | (4 | ) | | (3 | ) | |
Unrealized gain (loss) on foreign currency translation | 7 |
| | 10 |
| | (21 | ) | |
Unrealized gain (loss) on investments in unconsolidated affiliates | | 2 |
| | 4 |
| | (4 | ) |
Unrealized (loss) gain on foreign currency translation | | (10 | ) | | 7 |
| | 10 |
|
Other comprehensive income (loss) | 171 |
|
| (36 | ) |
| 60 |
| 42 |
|
| 171 |
|
| (36 | ) |
Comprehensive income | 4,020 |
|
| 1,168 |
|
| 2,310 |
| 2,126 |
|
| 4,047 |
|
| 1,160 |
|
Comprehensive income (loss) attributable to noncontrolling interests and preference stock dividends | 77 |
| | 70 |
| | (19 | ) | |
Comprehensive income attributable to noncontrolling interests and preference stock dividends | | 75 |
| | 88 |
| | 75 |
|
Comprehensive income attributable to common shareholders | $ | 3,943 |
| | $ | 1,098 |
|
| $ | 2,329 |
| $ | 2,051 |
| | $ | 3,959 |
|
| $ | 1,085 |
|
| | | | | | | | | | |
Average shares of common stock outstanding: | | | | | | | | | | |
Basic | 947 |
| | 924 |
| | 890 |
| 967 |
| | 947 |
| | 924 |
|
Diluted | 949 |
| | 927 |
| | 893 |
| 969 |
| | 949 |
| | 927 |
|
Earnings per average common share: | | | | | | | | | | |
Basic | $ | 3.98 |
| | $ | 1.23 |
| | $ | 2.55 |
| $ | 2.08 |
| | $ | 4.00 |
| | $ | 1.21 |
|
Diluted | $ | 3.97 |
|
| $ | 1.22 |
| | $ | 2.54 |
| $ | 2.07 |
|
| $ | 3.99 |
| | $ | 1.21 |
|
Dividends per common share | $ | 1.31 |
| | $ | 1.26 |
| | $ | 1.24 |
| |
See the Combined Notes to Consolidated Financial Statements
267212
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 3,849 |
| | $ | 1,204 |
| | $ | 2,250 |
| $ | 2,084 |
| | $ | 3,876 |
| | $ | 1,196 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 5,427 |
| | 5,576 |
| | 3,987 |
| 5,971 |
| | 5,427 |
| | 5,576 |
|
Impairment losses of long-lived assets, intangibles and regulatory assets | 573 |
| | 306 |
| | 36 |
| 50 |
| | 573 |
| | 306 |
|
Gain on deconsolidation of business
| (213 | ) | | — |
| | — |
| — |
| | (213 | ) | | — |
|
(Gain) Loss on sales of assets | (3 | ) | | 48 |
| | (18 | ) | |
(Gain) loss on sales of assets and businesses | | (56 | ) | | (3 | ) | | 48 |
|
Bargain purchase gain | (233 | ) | | — |
| | — |
| — |
| | (233 | ) | | — |
|
Deferred income taxes and amortization of investment tax credits | (361 | ) | | 664 |
| | 752 |
| (106 | ) | | (362 | ) | | 656 |
|
Net fair value changes related to derivatives | 151 |
| | 24 |
| | (367 | ) | 294 |
| | 151 |
| | 24 |
|
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (616 | ) | | (229 | ) | | 131 |
| |
Net realized and unrealized losses (gains) on NDT funds | | 303 |
| | (616 | ) | | (229 | ) |
Other non-cash operating activities | 721 |
| | 1,333 |
| | 1,109 |
| 1,124 |
| | 721 |
| | 1,333 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (426 | ) | | (432 | ) | | 240 |
| (565 | ) | | (470 | ) | | (432 | ) |
Inventories | (72 | ) | | 7 |
| | 4 |
| (37 | ) | | (72 | ) | | 7 |
|
Accounts payable and accrued expenses | (390 | ) | | 771 |
| | (121 | ) | 551 |
| | (388 | ) | | 771 |
|
Option premiums received (paid), net | 28 |
| | (66 | ) | | 58 |
| |
Collateral (posted) received, net | (158 | ) | | 931 |
| | 347 |
| |
Option premiums (paid) received, net | | (43 | ) | | 28 |
| | (66 | ) |
Collateral received (posted), net | | 82 |
| | (158 | ) | | 931 |
|
Income taxes | 299 |
| | 576 |
| | 97 |
| 340 |
| | 299 |
| | 576 |
|
Pension and non-pension postretirement benefit contributions | (405 | ) | | (397 | ) | | (502 | ) | (383 | ) | | (405 | ) | | (397 | ) |
Deposit with IRS | — |
| | (1,250 | ) | | — |
| — |
| | — |
| | (1,250 | ) |
Other assets and liabilities | (691 | ) | | (621 | ) | | (387 | ) | (965 | ) | | (675 | ) | | (589 | ) |
Net cash flows provided by operating activities | 7,480 |
|
| 8,445 |
|
| 7,616 |
| 8,644 |
|
| 7,480 |
|
| 8,461 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (7,584 | ) | | (8,553 | ) | | (7,624 | ) | (7,594 | ) | | (7,584 | ) | | (8,553 | ) |
Proceeds from termination of direct financing lease investment | — |
| | 360 |
| | — |
| — |
| | — |
| | 360 |
|
Proceeds from nuclear decommissioning trust fund sales | 7,845 |
| | 9,496 |
| | 6,895 |
| |
Investment in nuclear decommissioning trust funds | (8,113 | ) | | (9,738 | ) | | (7,147 | ) | |
Acquisitions of businesses, net | (208 | ) | | (6,934 | ) | | (40 | ) | |
Proceeds from sales of long-lived assets | 219 |
| | 61 |
| | 147 |
| |
Change in restricted cash | (50 | ) | | (42 | ) | | 66 |
| |
Proceeds from NDT fund sales | | 8,762 |
| | 7,845 |
| | 9,496 |
|
Investment in NDT funds | | (8,997 | ) | | (8,113 | ) | | (9,738 | ) |
Reduction of restricted cash from deconsolidation of business | | — |
| | (87 | ) | | — |
|
Acquisitions of assets and businesses, net | | (154 | ) | | (208 | ) | | (6,923 | ) |
Proceeds from sales of assets and businesses | | 91 |
| | 219 |
| | 61 |
|
Other investing activities | (43 | ) | | (153 | ) | | (119 | ) | 58 |
| | (43 | ) | | (153 | ) |
Net cash flows used in investing activities | (7,934 | ) |
| (15,503 | ) |
| (7,822 | ) | (7,834 | ) |
| (7,971 | ) |
| (15,450 | ) |
Cash flows from financing activities | | | | | | | | | | |
Changes in short-term borrowings | (261 | ) | | (353 | ) | | 80 |
| (338 | ) | | (261 | ) | | (353 | ) |
Proceeds from short-term borrowings with maturities greater than 90 days | 621 |
| | 240 |
| | — |
| 126 |
| | 621 |
| | 240 |
|
Repayments on short-term borrowings with maturities greater than 90 days | (700 | ) | | (462 | ) | | — |
| (1 | ) | | (700 | ) | | (462 | ) |
Issuance of long-term debt | 3,470 |
| | 4,716 |
| | 6,709 |
| 3,115 |
| | 3,470 |
| | 4,716 |
|
Retirement of long-term debt | (2,490 | ) | | (1,936 | ) | | (2,687 | ) | (1,786 | ) | | (2,490 | ) | | (1,936 | ) |
Retirement of long-term debt to financing trust | (250 | ) | | — |
| | — |
| — |
| | (250 | ) | | — |
|
Restricted proceeds from issuance of long-term debt | (50 | ) | | — |
| | — |
| |
Issuance of common stock | — |
| | — |
| | 1,868 |
| |
Common stock issued from treasury stock
| 1,150 |
| | — |
| | — |
| — |
| | 1,150 |
| | — |
|
Redemption of preference stock | — |
| | (190 | ) | | — |
| — |
| | — |
| | (190 | ) |
Dividends paid on common stock | (1,236 | ) | | (1,166 | ) | | (1,105 | ) | (1,332 | ) | | (1,236 | ) | | (1,166 | ) |
Proceeds from employee stock plans | 150 |
| | 55 |
| | 32 |
| 105 |
| | 150 |
| | 55 |
|
Sale of noncontrolling interests | 396 |
| | 372 |
| | 32 |
| — |
| | 396 |
| | 372 |
|
Other financing activities | (83 | ) | | (85 | ) | | (99 | ) | (108 | ) | | (83 | ) | | (85 | ) |
Net cash flows provided by financing activities | 717 |
|
| 1,191 |
|
| 4,830 |
| |
Increase (Decrease) in cash and cash equivalents | 263 |
| | (5,867 | ) | | 4,624 |
| |
Cash and cash equivalents at beginning of period | 635 |
| | 6,502 |
| | 1,878 |
| |
Cash and cash equivalents at end of period | $ | 898 |
|
| $ | 635 |
|
| $ | 6,502 |
| |
Net cash flows (used in) provided by financing activities | | (219 | ) |
| 767 |
|
| 1,191 |
|
Increase (decrease) in cash, cash equivalents and restricted cash | | 591 |
| | 276 |
| | (5,798 | ) |
Cash, cash equivalents and restricted cash at beginning of period | | 1,190 |
| | 914 |
| | 6,712 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 1,781 |
|
| $ | 1,190 |
|
| $ | 914 |
|
See the Combined Notes to Consolidated Financial Statements
268213
ExelonExelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 898 |
| | $ | 635 |
| $ | 1,349 |
| | $ | 898 |
|
Restricted cash and cash equivalents | 207 |
| | 253 |
| 247 |
| | 207 |
|
Deposit with IRS | — |
| | 1,250 |
| |
Accounts receivable, net | | | | | | |
Customer | 4,401 |
| | 4,158 |
| 4,607 |
| | 4,445 |
|
Other | 1,132 |
| | 1,201 |
| 1,256 |
| | 1,132 |
|
Mark-to-market derivative assets | 976 |
| | 917 |
| 804 |
| | 976 |
|
Unamortized energy contract assets | 60 |
| | 88 |
| 48 |
| | 60 |
|
Inventories, net | | | | | | |
Fossil fuel and emission allowances | 340 |
| | 364 |
| 334 |
| | 340 |
|
Materials and supplies | 1,311 |
| | 1,274 |
| 1,351 |
| | 1,311 |
|
Regulatory assets | 1,267 |
| | 1,342 |
| 1,222 |
| | 1,267 |
|
Assets held for sale | | 904 |
|
| — |
|
Other | 1,242 |
| | 930 |
| 1,238 |
| | 1,260 |
|
Total current assets | 11,834 |
|
| 12,412 |
| 13,360 |
|
| 11,896 |
|
Property, plant and equipment, net | 74,202 |
| | 71,555 |
| 76,707 |
| | 74,202 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 8,021 |
| | 10,046 |
| 8,237 |
| | 8,021 |
|
Nuclear decommissioning trust funds | 13,272 |
| | 11,061 |
| 11,661 |
| | 13,272 |
|
Investments | 640 |
| | 629 |
| 625 |
| | 640 |
|
Goodwill | 6,677 |
| | 6,677 |
| 6,677 |
| | 6,677 |
|
Mark-to-market derivative assets | 337 |
| | 492 |
| 452 |
| | 337 |
|
Unamortized energy contract assets | 395 |
| | 447 |
| 372 |
| | 395 |
|
Pledged assets for Zion Station decommissioning | — |
| | 113 |
| |
Other | 1,322 |
| | 1,472 |
| 1,575 |
| | 1,330 |
|
Total deferred debits and other assets | 30,664 |
|
| 30,937 |
| 29,599 |
|
| 30,672 |
|
Total assets(a) | $ | 116,700 |
|
| $ | 114,904 |
| $ | 119,666 |
|
| $ | 116,770 |
|
See the Combined Notes to Consolidated Financial Statements
269214
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 929 |
| | $ | 1,267 |
| $ | 714 |
| | $ | 929 |
|
Long-term debt due within one year | 2,088 |
| | 2,430 |
| 1,349 |
| | 2,088 |
|
Accounts payable | 3,532 |
| | 3,441 |
| 3,800 |
| | 3,532 |
|
Accrued expenses | 1,835 |
| | 3,460 |
| 2,112 |
| | 1,837 |
|
Payables to affiliates | 5 |
| | 8 |
| 5 |
| | 5 |
|
Regulatory liabilities | 523 |
| | 602 |
| 644 |
| | 523 |
|
Mark-to-market derivative liabilities | 232 |
| | 282 |
| 475 |
| | 232 |
|
Unamortized energy contract liabilities | 231 |
| | 407 |
| 149 |
| | 231 |
|
Renewable energy credit obligation | 352 |
| | 428 |
| 344 |
| | 352 |
|
PHI Merger related obligation | 87 |
| | 151 |
| |
Liabilities held for sale | | 777 |
| | — |
|
Other | 982 |
| | 981 |
| 1,035 |
| | 1,069 |
|
Total current liabilities | 10,796 |
|
| 13,457 |
| 11,404 |
|
| 10,798 |
|
Long-term debt | 32,176 |
| | 31,575 |
| 34,075 |
| | 32,176 |
|
Long-term debt to financing trusts | 389 |
| | 641 |
| 390 |
| | 389 |
|
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 11,222 |
| | 18,138 |
| 11,330 |
| | 11,235 |
|
Asset retirement obligations | 10,029 |
| | 9,111 |
| 9,679 |
| | 10,029 |
|
Pension obligations | 3,736 |
| | 4,248 |
| 3,988 |
| | 3,736 |
|
Non-pension postretirement benefit obligations | 2,093 |
| | 1,848 |
| 1,928 |
| | 2,093 |
|
Spent nuclear fuel obligation | 1,147 |
| | 1,024 |
| 1,171 |
| | 1,147 |
|
Regulatory liabilities | 9,865 |
| | 4,187 |
| 9,559 |
| | 9,865 |
|
Mark-to-market derivative liabilities | 409 |
| | 392 |
| 479 |
| | 409 |
|
Unamortized energy contract liabilities | 609 |
| | 830 |
| 463 |
| | 609 |
|
Payable for Zion Station decommissioning | — |
| | 14 |
| |
Other | 2,097 |
| | 1,827 |
| 2,130 |
| | 2,097 |
|
Total deferred credits and other liabilities | 41,207 |
|
| 41,619 |
| 40,727 |
|
| 41,220 |
|
Total liabilities(a) | 84,568 |
|
| 87,292 |
| 86,596 |
|
| 84,583 |
|
Commitments and contingencies | | | |
| |
|
Shareholders’ equity | | | | | | |
Common stock (No par value, 2000 shares authorized, 963 shares and 924 shares outstanding at December 31, 2017 and 2016, respectively) | 18,964 |
| | 18,794 |
| |
Treasury stock, at cost (2 shares and 35 shares at December 31, 2017 and 2016, respectively) | (123 | ) | | (2,327 | ) | |
Common stock (No par value, 2,000 shares authorized, 968 shares and 963 shares outstanding at December 31, 2018 and 2017, respectively) | | 19,116 |
| | 18,964 |
|
Treasury stock, at cost (2 shares at December 31, 2018 and 2017) | | (123 | ) | | (123 | ) |
Retained earnings | 13,503 |
| | 12,030 |
| 14,766 |
| | 14,081 |
|
Accumulated other comprehensive loss, net | (2,487 | ) | | (2,660 | ) | (2,995 | ) | | (3,026 | ) |
Total shareholders’ equity | 29,857 |
|
| 25,837 |
| 30,764 |
|
| 29,896 |
|
Noncontrolling interests | 2,275 |
| | 1,775 |
| 2,306 |
| | 2,291 |
|
Total equity | 32,132 |
|
| 27,612 |
| 33,070 |
|
| 32,187 |
|
Total liabilities and equity | $ | 116,700 |
|
| $ | 114,904 |
| $ | 119,666 |
|
| $ | 116,770 |
|
__________
| |
(a) | Exelon’s consolidated assets include $9,565$9,667 million and $8,893$9,597 million at December 31, 20172018 and December 31, 2016,2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,612$3,548 million and $3,356$3,618 million at December 31, 20172018 and December 31, 2016,2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–2–Variable Interest Entities. Entities for additional information. |
See the Combined Notes to Consolidated Financial Statements
270215
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | | Shareholders' Equity | | | | | | | Shareholders' Equity | | | | | | |
(In millions, shares in thousands) | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Noncontrolling Interests | | Preference Stock | | Total Equity | Issued Shares | | Common Stock | | Treasury Stock | | Retained Earnings | | Accumulated Other Comprehensive Loss | | Noncontrolling Interests | | Preference Stock | | Total Equity |
Balance, December 31, 2014 | 894,568 |
| | $ | 16,709 |
| | $ | (2,327 | ) | | $ | 10,910 |
| | $ | (2,684 | ) | | $ | 1,332 |
| | $ | 193 |
| | $ | 24,133 |
| |
Net income (loss) | — |
| | — |
| | — |
| | 2,269 |
| | — |
| | (32 | ) | | 13 |
| | 2,250 |
| |
Long-term incentive plan activity | 1,430 |
| | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 70 |
| |
Employee stock purchase plan issuances | 1,170 |
| | 32 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 32 |
| |
Issuance of common stock | 57,500 |
| | 1,868 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1,868 |
| |
Tax benefit on stock compensation | — |
| | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) | |
Acquisition of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
| |
Adjustment of contingently redeemable noncontrolling interests due to release of contingency
| — |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| | — |
| | 4 |
| |
Common stock dividends | — |
| | — |
| | — |
| | (1,111 | ) | | — |
| | — |
| | — |
| | (1,111 | ) | |
Preference stock dividends | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (13 | ) | | (13 | ) | |
Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 60 |
| | — |
| | — |
| | 60 |
| |
Balance, December 31, 2015 | 954,668 |
|
| $ | 18,676 |
|
| $ | (2,327 | ) |
| $ | 12,068 |
|
| $ | (2,624 | ) |
| $ | 1,308 |
|
| $ | 193 |
|
| $ | 27,294 |
| 954,668 |
| | $ | 18,676 |
| | $ | (2,327 | ) | | $ | 12,104 |
| | $ | (2,624 | ) | | $ | 1,308 |
| | $ | 193 |
| | $ | 27,330 |
|
Net income | — |
| | — |
| | — |
| | 1,134 |
| | — |
| | 62 |
| | 8 |
| | 1,204 |
| — |
| | — |
| | — |
| | 1,121 |
| | — |
| | 67 |
| | 8 |
| | 1,196 |
|
Long-term incentive plan activity | 2,868 |
| | 85 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 85 |
| 2,868 |
| | 85 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 85 |
|
Employee stock purchase plan issuances | 1,242 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 55 |
| 1,242 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 55 |
|
Tax benefit on stock compensation | — |
| | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) | — |
| | (18 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (18 | ) |
Changes in equity of noncontrolling interests
| — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
|
Sale of noncontrolling interest | — |
| | (4 | ) | | — |
| | — |
| | — |
| | 243 |
| | — |
| | 239 |
| |
Adjustment of contingently redeemable noncontrolling interests due to release of contingency | — |
| | — |
| | — |
| | — |
| | — |
| | 157 |
| | — |
| | 157 |
| |
Common stock dividends | — |
| | — |
| | — |
| | (1,172 | ) | | — |
| | — |
| | — |
| | (1,172 | ) | |
Adjustment of contingently redeemable noncontrolling interest to redemption value | | — |
| | — |
| | — |
| | — |
| | — |
| | 157 |
| | — |
| | 157 |
|
Common stock dividends ($1.26/common share) | | — |
| | — |
| | — |
| | (1,172 | ) | | — |
| | — |
| | — |
| | (1,172 | ) |
Preferred and preference stock | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (8 | ) |
Sale of noncontrolling interests | | — |
| | (4 | ) | | — |
| | — |
| | — |
| | 243 |
| | — |
| | 239 |
|
Redemption of preference stock
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (193 | ) | | (193 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (193 | ) | | (193 | ) |
Preference stock dividends | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (8 | ) | |
Other comprehensive loss, net of income taxes | — |
| | — |
| | — |
| | — |
| | (36 | ) | | — |
| | — |
| | (36 | ) | — |
| | — |
| | — |
| | — |
| | (36 | ) | | — |
| | — |
| | (36 | ) |
Balance, December 31, 2016 | 958,778 |
|
| $ | 18,794 |
|
| $ | (2,327 | ) |
| $ | 12,030 |
|
| $ | (2,660 | ) |
| $ | 1,775 |
|
| $ | — |
|
| $ | 27,612 |
| 958,778 |
|
| $ | 18,794 |
|
| $ | (2,327 | ) |
| $ | 12,053 |
|
| $ | (2,660 | ) |
| $ | 1,780 |
|
| $ | — |
|
| $ | 27,640 |
|
Net income | — |
| | — |
| | — |
| | 3,770 |
| | — |
| | 79 |
| | — |
| | 3,849 |
| — |
| | — |
| | — |
| | 3,786 |
| | — |
| | 90 |
| | — |
| | 3,876 |
|
Long-term incentive plan activity | 5,066 |
| | 56 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
| 5,066 |
| | 56 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
|
Employee stock purchase plan issuances | 1,324 |
| | 150 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 150 |
| 1,324 |
| | 150 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 150 |
|
Common stock issued from treasury stock | — |
| | — |
| | 2,204 |
| | (1,054 | ) | | — |
| | — |
| | — |
| | 1,150 |
| — |
| | — |
| | 2,204 |
| | (1,054 | ) | | — |
| | — |
| | — |
| | 1,150 |
|
Sale of noncontrolling interests | | — |
| | (36 | ) | | — |
| | — |
| | — |
| | 443 |
| | — |
| | 407 |
|
Changes in equity of noncontrolling interests | | — |
| | — |
| | — |
| | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
Common stock dividends ($1.31/common share) | | — |
| | — |
| | — |
| | (1,243 | ) | | — |
| | — |
| | — |
| | (1,243 | ) |
Other comprehensive income (loss), net of income taxes | | — |
| | — |
| | — |
| | — |
| | 173 |
| | (2 | ) | | — |
| | 171 |
|
Impact of adoption of Reclassification of Certain Tax Effects from AOCI standard | | — |
| | — |
| | — |
| | 539 |
| | (539 | ) | | — |
| | — |
| | — |
|
Balance, December 31, 2017 | | 965,168 |
|
| $ | 18,964 |
|
| $ | (123 | ) |
| $ | 14,081 |
|
| $ | (3,026 | ) |
| $ | 2,291 |
|
| $ | — |
|
| $ | 32,187 |
|
Net income | | — |
| | — |
| | — |
| | 2,010 |
| | — |
| | 74 |
| | — |
| | 2,084 |
|
Long-term incentive plan activity | | 3,534 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 41 |
|
Employee stock purchase plan issuances | | 1,318 |
| | 105 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 105 |
|
Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (60 | ) | | — |
| | (60 | ) |
Sale of noncontrolling interests | — |
| | (36 | ) | | — |
| | — |
| | — |
| | 443 |
| | — |
| | 407 |
| — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Common stock dividends | — |
| | — |
| | — |
| | (1,243 | ) | | — |
| | — |
| | — |
| | (1,243 | ) | |
Common stock dividends ($1.38/common share)
| | — |
| | — |
| | — |
| | (1,339 | ) | | — |
| | — |
| | — |
| | (1,339 | ) |
Other comprehensive income, net of income taxes | — |
| | — |
| | — |
| | — |
| | 173 |
| | (2 | ) | | — |
| | 171 |
| — |
| | — |
| | — |
| | — |
| | 41 |
| | 1 |
| | — |
| | 42 |
|
Balance, December 31, 2017 | 965,168 |
|
| $ | 18,964 |
|
| $ | (123 | ) |
| $ | 13,503 |
|
| $ | (2,487 | ) |
| $ | 2,275 |
|
| $ | — |
|
| $ | 32,132 |
| |
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard
| | — |
| | — |
| | — |
| | 14 |
| | (10 | ) | | — |
| | — |
| | 4 |
|
Balance, December 31, 2018 | | 970,020 |
|
| $ | 19,116 |
|
| $ | (123 | ) |
| $ | 14,766 |
|
| $ | (2,995 | ) |
| $ | 2,306 |
|
| $ | — |
|
| $ | 33,070 |
|
See the Combined Notes to Consolidated Financial Statements
271216
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Operating revenues | $ | 17,351 |
| | $ | 16,312 |
| | $ | 18,386 |
| $ | 19,169 |
| | $ | 17,385 |
| | $ | 16,318 |
|
Operating revenues from affiliates | 1,115 |
| | 1,439 |
| | 749 |
| 1,268 |
| | 1,115 |
| | 1,439 |
|
Total operating revenues | 18,466 |
|
| 17,751 |
|
| 19,135 |
| 20,437 |
|
| 18,500 |
|
| 17,757 |
|
Operating expenses | | | | | | | | | | |
Purchased power and fuel | 9,671 |
| | 8,818 |
| | 10,007 |
| 11,679 |
| | 9,671 |
| | 8,818 |
|
Purchased power and fuel from affiliates | 19 |
| | 12 |
| | 14 |
| 14 |
| | 19 |
| | 12 |
|
Operating and maintenance | 5,594 |
| | 4,978 |
| | 4,688 |
| 4,803 |
| | 5,602 |
| | 5,000 |
|
Operating and maintenance from affiliates | 697 |
| | 663 |
| | 620 |
| 661 |
| | 697 |
| | 663 |
|
Depreciation and amortization | 1,457 |
| | 1,879 |
| | 1,054 |
| 1,797 |
| | 1,457 |
| | 1,879 |
|
Taxes other than income | 555 |
| | 506 |
| | 489 |
| 556 |
| | 555 |
| | 506 |
|
Total operating expenses | 17,993 |
|
| 16,856 |
|
| 16,872 |
| 19,510 |
|
| 18,001 |
|
| 16,878 |
|
Gain (Loss) on sales of assets | 2 |
| | (59 | ) | | 12 |
| |
Gain (loss) on sales of assets and businesses | | 48 |
| | 2 |
| | (59 | ) |
Bargain purchase gain | 233 |
| | — |
| | — |
| — |
| | 233 |
| | — |
|
Gain on deconsolidation of business | 213 |
| | — |
| | — |
| — |
| | 213 |
| | — |
|
Operating income | 921 |
| | 836 |
| | 2,275 |
| 975 |
| | 947 |
| | 820 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (401 | ) | | (325 | ) | | (322 | ) | (396 | ) | | (401 | ) | | (325 | ) |
Interest expense to affiliates | (39 | ) | | (39 | ) | | (43 | ) | (36 | ) | | (39 | ) | | (39 | ) |
Other, net | 948 |
| | 401 |
| | (60 | ) | (178 | ) | | 948 |
| | 401 |
|
Total other income and (deductions) | 508 |
|
| 37 |
|
| (425 | ) | (610 | ) |
| 508 |
|
| 37 |
|
Income before income taxes | 1,429 |
| | 873 |
| | 1,850 |
| 365 |
| | 1,455 |
| | 857 |
|
Income taxes | (1,375 | ) | | 290 |
| | 502 |
| (108 | ) | | (1,376 | ) | | 282 |
|
Equity in losses of unconsolidated affiliates | (33 | ) | | (25 | ) | | (8 | ) | (30 | ) | | (33 | ) | | (25 | ) |
Net income | 2,771 |
|
| 558 |
|
| 1,340 |
| 443 |
|
| 2,798 |
|
| 550 |
|
Net income (loss) attributable to noncontrolling interests | 77 |
| | 62 |
| | (32 | ) | |
Net income attributable to noncontrolling interests | | 73 |
| | 88 |
| | 67 |
|
Net income attributable to membership interest | $ | 2,694 |
|
| $ | 496 |
|
| $ | 1,372 |
| $ | 370 |
|
| $ | 2,710 |
|
| $ | 483 |
|
Comprehensive income, net of income taxes | | | | | | | | | | |
Net income | $ | 2,771 |
| | $ | 558 |
| | $ | 1,340 |
| $ | 443 |
| | $ | 2,798 |
| | $ | 550 |
|
Other comprehensive income (loss), net of income taxes | | | | | | | | | | |
Unrealized gain (loss) on cash flow hedges | 3 |
| | 2 |
| | (3 | ) | |
Unrealized gain (loss) on equity investments | 4 |
| | (4 | ) | | (3 | ) | |
Unrealized gain (loss) on foreign currency translation | 7 |
| | 10 |
| | (21 | ) | |
Unrealized gain on cash flow hedges | | 12 |
| | 3 |
| | 2 |
|
Unrealized gain (loss) on investments in unconsolidated affiliates | | 1 |
| | 4 |
| | (4 | ) |
Unrealized (loss) gain on foreign currency translation | | (10 | ) | | 7 |
| | 10 |
|
Unrealized gain on marketable securities | 1 |
| | 1 |
| | — |
| — |
| | 1 |
| | 1 |
|
Other comprehensive income (loss) | 15 |
|
| 9 |
|
| (27 | ) | |
Other comprehensive income | | 3 |
|
| 15 |
|
| 9 |
|
Comprehensive income | $ | 2,786 |
|
| $ | 567 |
|
| $ | 1,313 |
| $ | 446 |
|
| $ | 2,813 |
|
| $ | 559 |
|
Comprehensive income (loss) attributable to noncontrolling interests | 75 |
| | 62 |
| | (32 | ) | |
Comprehensive income attributable to noncontrolling interests | | 74 |
| | 86 |
| | 67 |
|
Comprehensive income attributable to membership interest | $ | 2,711 |
| | $ | 505 |
| | $ | 1,345 |
| $ | 372 |
| | $ | 2,727 |
| | $ | 492 |
|
See the Combined Notes to Consolidated Financial Statements
272217
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows | | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 2,771 |
| | $ | 558 |
| | $ | 1,340 |
| $ | 443 |
| | $ | 2,798 |
| | $ | 550 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization | 3,056 |
| | 3,519 |
| | 2,589 |
| 3,415 |
| | 3,056 |
| | 3,519 |
|
Impairment losses of long-lived assets | 510 |
| | 243 |
| | 12 |
| 50 |
| | 510 |
| | 243 |
|
Gain on deconsolidation of business | (213 | ) | | — |
| | — |
| — |
| | (213 | ) | | — |
|
(Gain) Loss on sales of assets | (2 | ) | | 59 |
| | (12 | ) | |
(Gain) loss on sales of assets and businesses | | (48 | ) | | (2 | ) | | 59 |
|
Bargain purchase gain | (233 | ) | | — |
| | — |
| — |
| | (233 | ) | | — |
|
Deferred income taxes and amortization of investment tax credits | (2,022 | ) | | (269 | ) | | 49 |
| (451 | ) | | (2,023 | ) | | (277 | ) |
Net fair value changes related to derivatives | 167 |
| | 40 |
| | (249 | ) | 307 |
| | 167 |
| | 40 |
|
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments | (616 | ) | | (229 | ) | | 131 |
| |
Net realized and unrealized losses (gains) on NDT fund investments | | 303 |
| | (616 | ) | | (229 | ) |
Other non-cash operating activities | 112 |
| | 15 |
| | 268 |
| 298 |
| | 112 |
| | 15 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (276 | ) | | (152 | ) | | 194 |
| (359 | ) | | (320 | ) | | (152 | ) |
Receivables from and payables to affiliates, net | (7 | ) | | (21 | ) | | 15 |
| 8 |
| | (7 | ) | | (21 | ) |
Inventories | (29 | ) | | (4 | ) | | 16 |
| (12 | ) | | (29 | ) | | (4 | ) |
Accounts payable and accrued expenses | 2 |
| | 29 |
| | (149 | ) | 376 |
| | 4 |
| | 29 |
|
Option premiums received (paid), net | 28 |
| | (66 | ) | | 58 |
| |
Collateral (posted) received, net | (129 | ) | | 923 |
| | 407 |
| |
Option premiums (paid) received, net | | (43 | ) | | 28 |
| | (66 | ) |
Collateral received (posted), net | | 64 |
| | (129 | ) | | 923 |
|
Income taxes | 496 |
| | 182 |
| | (18 | ) | (193 | ) | | 496 |
| | 182 |
|
Pension and non-pension postretirement benefit contributions | (148 | ) | | (152 | ) | | (245 | ) | (139 | ) | | (148 | ) | | (152 | ) |
Other assets and liabilities | (168 | ) | | (231 | ) | | (207 | ) | (158 | ) | | (152 | ) | | (217 | ) |
Net cash flows provided by operating activities | 3,299 |
|
| 4,444 |
|
| 4,199 |
| 3,861 |
|
| 3,299 |
|
| 4,442 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (2,259 | ) | | (3,078 | ) | | (3,841 | ) | (2,242 | ) | | (2,259 | ) | | (3,078 | ) |
Proceeds from nuclear decommissioning trust fund sales | 7,845 |
| | 9,496 |
| | 6,895 |
| |
Investment in nuclear decommissioning trust funds | (8,113 | ) | | (9,738 | ) | | (7,147 | ) | |
Proceeds from sales of long-lived assets | 218 |
| | 37 |
| | 147 |
| |
Acquisitions of businesses, net | (208 | ) | | (293 | ) | | (40 | ) | |
Change in restricted cash | (17 | ) | | (35 | ) | | 35 |
| |
Proceeds from NDT fund sales | | 8,762 |
| | 7,845 |
| | 9,496 |
|
Investment in NDT funds | | (8,997 | ) | | (8,113 | ) | | (9,738 | ) |
Reduction of restricted cash from deconsolidation of business
| | — |
| | (87 | ) | | — |
|
Proceeds from sales of assets and businesses | | 90 |
| | 218 |
| | 37 |
|
Acquisitions of assets and businesses, net | | (154 | ) | | (208 | ) | | (293 | ) |
Other investing activities | (58 | ) | | (240 | ) | | (118 | ) | 10 |
| | (58 | ) | | (240 | ) |
Net cash flows used in investing activities | (2,592 | ) |
| (3,851 | ) |
| (4,069 | ) | (2,531 | ) |
| (2,662 | ) |
| (3,816 | ) |
Cash flows from financing activities | | | | | | | | | | |
Change in short-term borrowings | (620 | ) | | 620 |
| | — |
| — |
| | (620 | ) | | 620 |
|
Proceeds from short-term borrowings with maturities greater than 90 days | 121 |
| | 240 |
| | — |
| 1 |
| | 121 |
| | 240 |
|
Repayments of short-term borrowings with maturities greater than 90 days | (200 | ) | | (162 | ) | | — |
| (1 | ) | | (200 | ) | | (162 | ) |
Issuance of long-term debt | 1,645 |
| | 388 |
| | 1,309 |
| 15 |
| | 1,645 |
| | 388 |
|
Retirement of long-term debt | (1,261 | ) | | (202 | ) | | (89 | ) | (141 | ) | | (1,261 | ) | | (202 | ) |
Restricted proceeds from issuance of long-term debt | (50 | ) | | — |
| | — |
| |
Retirement of long-term debt to affiliate | — |
| | — |
| | (550 | ) | |
Changes in Exelon intercompany money pool | (1 | ) | | (1,191 | ) | | 1,252 |
| 46 |
| | (1 | ) | | (1,191 | ) |
Distributions to member | (659 | ) | | (922 | ) | | (2,474 | ) | (1,001 | ) | | (659 | ) | | (922 | ) |
Contributions from member | 102 |
| | 142 |
| | 47 |
| 155 |
| | 102 |
| | 142 |
|
Sale of noncontrolling interests | 396 |
| | 372 |
| | 32 |
| — |
| | 396 |
| | 372 |
|
Other financing activities | (54 | ) | | (19 | ) | | (6 | ) | (55 | ) | | (54 | ) | | (19 | ) |
Net cash flows used in financing activities | (581 | ) |
| (734 | ) |
| (479 | ) | (981 | ) |
| (531 | ) |
| (734 | ) |
Increase (Decrease) in cash and cash equivalents | 126 |
| | (141 | ) | | (349 | ) | |
Cash and cash equivalents at beginning of period | 290 |
| | 431 |
| | 780 |
| |
Cash and cash equivalents at end of period | $ | 416 |
|
| $ | 290 |
|
| $ | 431 |
| |
Increase (decrease) in cash, cash equivalents and restricted cash | | 349 |
| | 106 |
| | (108 | ) |
Cash, cash equivalents and restricted cash at beginning of period | | 554 |
| | 448 |
| | 556 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 903 |
|
| $ | 554 |
|
| $ | 448 |
|
See the Combined Notes to Consolidated Financial Statements
273218
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 416 |
| | $ | 290 |
| $ | 750 |
| | $ | 416 |
|
Restricted cash and cash equivalents | 138 |
| | 158 |
| 153 |
| | 138 |
|
Accounts receivable, net | | | | | | |
Customer | 2,653 |
| | 2,433 |
| 2,941 |
| | 2,697 |
|
Other | 321 |
| | 558 |
| 562 |
| | 321 |
|
Mark-to-market derivative assets | 976 |
| | 917 |
| 804 |
| | 976 |
|
Receivables from affiliates | 140 |
| | 156 |
| 173 |
| | 140 |
|
Unamortized energy contract assets | 60 |
| | 88 |
| 49 |
| | 60 |
|
Inventories, net | | | | | | |
Fossil fuel and emission allowances | 264 |
| | 292 |
| 251 |
| | 264 |
|
Materials and supplies | 937 |
| | 935 |
| 963 |
| | 937 |
|
Assets held for sale | | 904 |
| | — |
|
Other | 915 |
| | 701 |
| 883 |
| | 933 |
|
Total current assets | 6,820 |
|
| 6,528 |
| 8,433 |
|
| 6,882 |
|
Property, plant and equipment, net | 24,906 |
| | 25,585 |
| 23,981 |
| | 24,906 |
|
Deferred debits and other assets | | | | | | |
Nuclear decommissioning trust funds | 13,272 |
| | 11,061 |
| 11,661 |
| | 13,272 |
|
Investments | 433 |
| | 418 |
| 414 |
| | 433 |
|
Goodwill | 47 |
| | 47 |
| 47 |
| | 47 |
|
Mark-to-market derivative assets | 334 |
| | 476 |
| 452 |
| | 334 |
|
Prepaid pension asset | 1,502 |
| | 1,595 |
| 1,421 |
| | 1,502 |
|
Pledged assets for Zion Station decommissioning | — |
| | 113 |
| |
Unamortized energy contract assets | 395 |
| | 447 |
| 371 |
| | 395 |
|
Deferred income taxes | 16 |
| | 16 |
| 21 |
| | 16 |
|
Other | 662 |
| | 688 |
| 755 |
| | 670 |
|
Total deferred debits and other assets | 16,661 |
|
| 14,861 |
| 15,142 |
|
| 16,669 |
|
Total assets(a) | $ | 48,387 |
|
| $ | 46,974 |
| $ | 47,556 |
|
| $ | 48,457 |
|
See the Combined Notes to Consolidated Financial Statements
274219
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 2 |
| | $ | 699 |
| $ | — |
| | $ | 2 |
|
Long-term debt due within one year | 346 |
| | 1,117 |
| 906 |
| | 346 |
|
Accounts payable | 1,773 |
| | 1,610 |
| 1,847 |
| | 1,773 |
|
Accrued expenses | 1,020 |
| | 989 |
| 898 |
| | 1,022 |
|
Payables to affiliates | 123 |
| | 137 |
| 139 |
| | 123 |
|
Borrowings from Exelon intercompany money pool | 54 |
| | 55 |
| 100 |
| | 54 |
|
Mark-to-market derivative liabilities | 211 |
| | 263 |
| 449 |
| | 211 |
|
Unamortized energy contract liabilities | 43 |
| | 72 |
| 31 |
| | 43 |
|
Renewable energy credit obligation | 352 |
| | 428 |
| 343 |
| | 352 |
|
Liabilities held for sale | | 777 |
| | — |
|
Other | 265 |
| | 313 |
| 279 |
| | 265 |
|
Total current liabilities | 4,189 |
|
| 5,683 |
| 5,769 |
|
| 4,191 |
|
Long-term debt | 7,734 |
| | 7,202 |
| 6,989 |
| | 7,734 |
|
Long-term debt to affiliate | 910 |
| | 922 |
| |
Long-term debt to affiliates | | 898 |
| | 910 |
|
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 3,798 |
| | 5,585 |
| 3,383 |
| | 3,811 |
|
Asset retirement obligations | 9,844 |
| | 8,922 |
| 9,450 |
| | 9,844 |
|
Non-pension postretirement benefit obligations | 916 |
| | 930 |
| 900 |
| | 916 |
|
Spent nuclear fuel obligation | 1,147 |
| | 1,024 |
| 1,171 |
| | 1,147 |
|
Payables to affiliates | 3,065 |
| | 2,608 |
| 2,606 |
| | 3,065 |
|
Mark-to-market derivative liabilities | 174 |
| | 153 |
| 252 |
| | 174 |
|
Unamortized energy contract liabilities | 48 |
| | 80 |
| 20 |
| | 48 |
|
Payable for Zion Station decommissioning | — |
| | 14 |
| |
Other | 658 |
| | 595 |
| 610 |
| | 658 |
|
Total deferred credits and other liabilities | 19,650 |
|
| 19,911 |
| 18,392 |
|
| 19,663 |
|
Total liabilities(a) | 32,483 |
|
| 33,718 |
| 32,048 |
|
| 32,498 |
|
Commitments and contingencies | |
| |
|
Equity | | | | | | |
Member’s equity | | | | | | |
Membership interest | 9,357 |
| | 9,261 |
| 9,518 |
| | 9,357 |
|
Undistributed earnings | 4,310 |
| | 2,275 |
| 3,724 |
| | 4,349 |
|
Accumulated other comprehensive loss, net | (37 | ) | | (54 | ) | (38 | ) | | (37 | ) |
Total member’s equity | 13,630 |
|
| 11,482 |
| 13,204 |
|
| 13,669 |
|
Noncontrolling interests | 2,274 |
| | 1,774 |
| 2,304 |
| | 2,290 |
|
Total equity | 15,904 |
|
| 13,256 |
| 15,508 |
|
| 15,959 |
|
Total liabilities and equity | $ | 48,387 |
|
| $ | 46,974 |
| $ | 47,556 |
|
| $ | 48,457 |
|
__________
| |
(a) | Generation’s consolidated assets include $9,524$9,634 million and $8,817$9,556 million at December 31, 20172018 and 2016,2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,510$3,480 million and $3,170$3,516 million at December 31, 20172018 and 2016,2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.Entities for additional information. |
See the Combined Notes to Consolidated Financial Statements
275220
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
| |
| Member’s Equity |
| Noncontrolling Interests |
| Total Equity | Member’s Equity |
| Noncontrolling Interests |
| Total Equity |
(In millions) | Membership Interest |
| Undistributed Earnings |
| Accumulated Other Comprehensive Loss, net |
| Membership Interest |
| Undistributed Earnings |
| Accumulated Other Comprehensive Loss, net |
|
Balance, December 31, 2014 | $ | 8,951 |
| | $ | 3,803 |
| | $ | (36 | ) | | $ | 1,333 |
| | $ | 14,051 |
| |
Net income (loss) | — |
|
| 1,372 |
|
| — |
|
| (32 | ) |
| 1,340 |
| |
Acquisition of noncontrolling interests | (1 | ) |
| — |
|
| — |
|
| 2 |
|
| 1 |
| |
Adjustment of contingently redeemable noncontrolling interests due to release of contingency | — |
| | — |
| | — |
| | 4 |
| | 4 |
| |
Allocation of tax benefit from member | 47 |
|
| — |
|
| — |
|
| — |
|
| 47 |
| |
Distribution to member | — |
| | (2,474 | ) | | — |
| | — |
| | (2,474 | ) | |
Other comprehensive loss, net of income taxes | — |
|
| — |
|
| (27 | ) |
| — |
|
| (27 | ) | |
Balance, December 31, 2015 | $ | 8,997 |
|
| $ | 2,701 |
|
| $ | (63 | ) |
| $ | 1,307 |
|
| $ | 12,942 |
| $ | 8,997 |
| | $ | 2,737 |
| | $ | (63 | ) | | $ | 1,307 |
| | $ | 12,978 |
|
Net income | — |
|
| 496 |
|
| — |
|
| 62 |
|
| 558 |
| — |
|
| 483 |
|
| — |
|
| 67 |
|
| 550 |
|
Sale of noncontrolling interests | (4 | ) | | — |
| | — |
| | 243 |
| | 239 |
| (4 | ) |
| — |
|
| — |
|
| 243 |
|
| 239 |
|
Adjustment of contingently redeemable noncontrolling interests due to release of contingency | — |
|
| — |
|
| — |
|
| 157 |
|
| 157 |
| — |
| | — |
| | — |
| | 157 |
| | 157 |
|
Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | 5 |
| | 5 |
| — |
| | — |
| | — |
| | 5 |
| | 5 |
|
Allocation of tax benefit from member | 98 |
|
| — |
|
| — |
|
| — |
|
| 98 |
| |
Contribution from member | 170 |
| | — |
| | — |
| | — |
| | 170 |
| |
Distribution to member | — |
|
| (922 | ) |
| — |
|
| — |
|
| (922 | ) | |
Contributions from member | | 268 |
| | — |
| | — |
| | — |
| | 268 |
|
Distributions to member | | — |
| | (922 | ) | | — |
| | — |
| | (922 | ) |
Other comprehensive income, net of income taxes | — |
|
| — |
|
| 9 |
|
| — |
|
| 9 |
| — |
|
| — |
|
| 9 |
|
| — |
|
| 9 |
|
Balance, December 31, 2016 | $ | 9,261 |
|
| $ | 2,275 |
|
| $ | (54 | ) |
| $ | 1,774 |
|
| $ | 13,256 |
| $ | 9,261 |
|
| $ | 2,298 |
|
| $ | (54 | ) |
| $ | 1,779 |
|
| $ | 13,284 |
|
Net income | — |
| | 2,694 |
| | — |
| | 77 |
| | 2,771 |
| — |
|
| 2,710 |
|
| — |
|
| 88 |
|
| 2,798 |
|
Sale of noncontrolling interests | (36 | ) | | — |
| | — |
| | 443 |
| | 407 |
| (36 | ) | | — |
| | — |
| | 443 |
| | 407 |
|
Changes in equity of noncontrolling interests | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) | — |
| | — |
| | — |
| | (18 | ) | | (18 | ) |
Distribution of net retirement benefit obligation to member | 33 |
| | — |
| | — |
| | — |
| | 33 |
| 33 |
|
| — |
|
| — |
|
| — |
|
| 33 |
|
Allocation of tax benefit from member | 99 |
| | — |
| | — |
| | — |
| | 99 |
| |
Distribution to member | — |
| | (659 | ) | | — |
| | — |
| | (659 | ) | |
Contributions from member | | 99 |
| | — |
| | — |
| | — |
| | 99 |
|
Distributions to member | | — |
|
| (659 | ) |
| — |
|
| — |
|
| (659 | ) |
Other comprehensive income (loss), net of income taxes | | — |
|
| — |
|
| 17 |
|
| (2 | ) |
| 15 |
|
Balance, December 31, 2017 | | $ | 9,357 |
|
| $ | 4,349 |
|
| $ | (37 | ) |
| $ | 2,290 |
|
| $ | 15,959 |
|
Net income | | — |
| | 370 |
| | — |
| | 73 |
| | 443 |
|
Sale of noncontrolling interests | | 6 |
| | — |
| | — |
| | — |
| | 6 |
|
Changes in equity of noncontrolling interests | | — |
| | — |
| | — |
| | (60 | ) | | (60 | ) |
Contributions from member | | 155 |
| | — |
| | — |
| | — |
| | 155 |
|
Distributions to member | | — |
| | (1,001 | ) | | — |
| | — |
| | (1,001 | ) |
Other comprehensive income, net of income taxes | — |
| | — |
| | 17 |
| | (2 | ) | | 15 |
| — |
| | — |
| | 2 |
| | 1 |
| | 3 |
|
Balance, December 31, 2017 | $ | 9,357 |
| | $ | 4,310 |
| | $ | (37 | ) | | $ | 2,274 |
| | $ | 15,904 |
| |
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | | — |
| | 6 |
| | (3 | ) | | — |
| | 3 |
|
Balance, December 31, 2018 | | $ | 9,518 |
| | $ | 3,724 |
| | $ | (38 | ) | | $ | 2,304 |
| | $ | 15,508 |
|
See the Combined Notes to Consolidated Financial Statements
276221
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 5,521 |
| | $ | 5,239 |
| | $ | 4,901 |
| $ | 5,884 |
| | $ | 5,478 |
| | $ | 5,263 |
|
Revenues from alternative revenue programs | | (29 | ) | | 43 |
| | (24 | ) |
Operating revenues from affiliates | 15 |
| | 15 |
| | 4 |
| 27 |
| | 15 |
| | 15 |
|
Total operating revenues | 5,536 |
| | 5,254 |
| | 4,905 |
| 5,882 |
| | 5,536 |
| | 5,254 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 1,533 |
| | 1,411 |
| | 1,301 |
| 1,626 |
| | 1,533 |
| | 1,411 |
|
Purchased power from affiliate | 108 |
| | 47 |
| | 18 |
| |
Purchased power from affiliates | | 529 |
| | 108 |
| | 47 |
|
Operating and maintenance | 1,157 |
| | 1,303 |
| | 1,372 |
| 1,068 |
| | 1,157 |
| | 1,303 |
|
Operating and maintenance from affiliate | 270 |
| | 227 |
| | 195 |
| |
Operating and maintenance from affiliates | | 267 |
| | 270 |
| | 227 |
|
Depreciation and amortization | 850 |
| | 775 |
| | 707 |
| 940 |
| | 850 |
| | 775 |
|
Taxes other than income | 296 |
| | 293 |
| | 296 |
| 311 |
| | 296 |
| | 293 |
|
Total operating expenses | 4,214 |
| | 4,056 |
| | 3,889 |
| 4,741 |
| | 4,214 |
| | 4,056 |
|
Gain on sales of assets | 1 |
| | 7 |
| | 1 |
| 5 |
| | 1 |
| | 7 |
|
Operating income | 1,323 |
| | 1,205 |
| | 1,017 |
| 1,146 |
| | 1,323 |
| | 1,205 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (348 | ) | | (448 | ) | | (319 | ) | (334 | ) | | (348 | ) | | (448 | ) |
Interest expense to affiliates | (13 | ) | | (13 | ) | | (13 | ) | (13 | ) | | (13 | ) | | (13 | ) |
Other, net | 22 |
| | (65 | ) | | 21 |
| 33 |
| | 22 |
| | (65 | ) |
Total other income and (deductions) | (339 | ) | | (526 | ) | | (311 | ) | (314 | ) | | (339 | ) | | (526 | ) |
Income before income taxes | 984 |
| | 679 |
| | 706 |
| 832 |
| | 984 |
| | 679 |
|
Income taxes | 417 |
| | 301 |
| | 280 |
| 168 |
| | 417 |
| | 301 |
|
Net income | $ | 567 |
| | $ | 378 |
| | $ | 426 |
| $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
Comprehensive income | $ | 567 |
| | $ | 378 |
| | $ | 426 |
| $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
See the Combined Notes to Consolidated Financial Statements
277222
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 567 |
| | $ | 378 |
| | $ | 426 |
| $ | 664 |
| | $ | 567 |
| | $ | 378 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation, amortization and accretion | 850 |
| | 775 |
| | 707 |
| 940 |
| | 850 |
| | 775 |
|
Deferred income taxes and amortization of investment tax credits | 659 |
| | 439 |
| | 353 |
| 259 |
| | 659 |
| | 439 |
|
Other non-cash operating activities | 164 |
| | 215 |
| | 416 |
| 242 |
| | 164 |
| | 215 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (59 | ) | | (25 | ) | | (93 | ) | (136 | ) | | (59 | ) | | (25 | ) |
Receivables from and payables to affiliates, net | 8 |
| | 3 |
| | (19 | ) | 26 |
| | 8 |
| | 3 |
|
Inventories | 4 |
| | 1 |
| | (40 | ) | 1 |
| | 4 |
| | 1 |
|
Accounts payable and accrued expenses | (297 | ) | | 339 |
| | 68 |
| 70 |
| | (297 | ) | | 339 |
|
Counterparty collateral received (posted), net and cash deposits | (26 | ) | | 7 |
| | (33 | ) | 11 |
| | (26 | ) | | 7 |
|
Income taxes | (308 | ) | | 306 |
| | 192 |
| 62 |
| | (308 | ) | | 306 |
|
Pension and non-pension postretirement benefit contributions | (41 | ) | | (38 | ) | | (150 | ) | (42 | ) | | (41 | ) | | (38 | ) |
Other assets and liabilities | 6 |
| | 105 |
| | 69 |
| (348 | ) | | 6 |
| | 105 |
|
Net cash flows provided by operating activities | 1,527 |
| | 2,505 |
| | 1,896 |
| 1,749 |
| | 1,527 |
| | 2,505 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (2,250 | ) | | (2,734 | ) | | (2,398 | ) | (2,126 | ) | | (2,250 | ) | | (2,734 | ) |
Change in restricted cash | (66 | ) | | — |
| | 2 |
| |
Other investing activities | 20 |
| | 49 |
| | 34 |
| 29 |
| | 20 |
| | 49 |
|
Net cash flows used in investing activities | (2,296 | ) | | (2,685 | ) | | (2,362 | ) | (2,097 | ) | | (2,230 | ) | | (2,685 | ) |
Cash flows from financing activities | | | | | | | | | | |
Changes in short-term borrowings | — |
| | (294 | ) | | (10 | ) | — |
| | — |
| | (294 | ) |
Issuance of long-term debt | 1,000 |
| | 1,200 |
| | 850 |
| 1,350 |
| | 1,000 |
| | 1,200 |
|
Retirement of long-term debt | (425 | ) | | (665 | ) | | (260 | ) | (840 | ) | | (425 | ) | | (665 | ) |
Contributions from parent | 651 |
| | 315 |
| | 202 |
| 500 |
| | 651 |
| | 315 |
|
Dividends paid on common stock | (422 | ) | | (369 | ) | | (299 | ) | (459 | ) | | (422 | ) | | (369 | ) |
Other financing activities | (15 | ) | | (18 | ) | | (16 | ) | (17 | ) | | (15 | ) | | (18 | ) |
Net cash flows provided by financing activities | 789 |
| | 169 |
| | 467 |
| 534 |
| | 789 |
| | 169 |
|
Increase (Decrease) in cash and cash equivalents | 20 |
| | (11 | ) | | 1 |
| |
Cash and cash equivalents at beginning of period | 56 |
| | 67 |
| | 66 |
| |
Cash and cash equivalents at end of period | $ | 76 |
| | $ | 56 |
| | $ | 67 |
| |
Increase (decrease) in cash, cash equivalents and restricted cash | | 186 |
| | 86 |
| | (11 | ) |
Cash, cash equivalents and restricted cash at beginning of period | | 144 |
| | 58 |
| | 69 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 330 |
| | $ | 144 |
| | $ | 58 |
|
See the Combined Notes to Consolidated Financial Statements
278223
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 76 |
| | $ | 56 |
| $ | 135 |
| | $ | 76 |
|
Restricted cash | 5 |
| | 2 |
| |
Restricted cash and cash equivalents | | 29 |
| | 5 |
|
Accounts receivable, net | | | | | | |
Customer | 559 |
| | 528 |
| 539 |
| | 559 |
|
Other | 266 |
| | 218 |
| 320 |
| | 266 |
|
Receivables from affiliates | 13 |
| | 356 |
| 20 |
| | 13 |
|
Inventories, net | 152 |
| | 159 |
| 148 |
| | 152 |
|
Regulatory assets | 225 |
| | 190 |
| 293 |
| | 225 |
|
Other | 68 |
| | 45 |
| 86 |
| | 68 |
|
Total current assets | 1,364 |
| | 1,554 |
| 1,570 |
| | 1,364 |
|
Property, plant and equipment, net | 20,723 |
| | 19,335 |
| 22,058 |
| | 20,723 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 1,054 |
| | 977 |
| 1,307 |
| | 1,054 |
|
Investments | 6 |
| | 6 |
| 6 |
| | 6 |
|
Goodwill | 2,625 |
| | 2,625 |
| 2,625 |
| | 2,625 |
|
Receivable from affiliates | 2,528 |
| | 2,170 |
| |
Receivables from affiliates | | 2,217 |
| | 2,528 |
|
Prepaid pension asset | 1,188 |
| | 1,343 |
| 1,035 |
| | 1,188 |
|
Other | 238 |
| | 325 |
| 395 |
| | 238 |
|
Total deferred debits and other assets | 7,639 |
| | 7,446 |
| 7,585 |
| | 7,639 |
|
Total assets | $ | 29,726 |
| | $ | 28,335 |
| $ | 31,213 |
| | $ | 29,726 |
|
See the Combined Notes to Consolidated Financial Statements
279224
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
Current liabilities | | | | | | |
Long-term debt due within one year | $ | 840 |
| | $ | 425 |
| $ | 300 |
| | $ | 840 |
|
Accounts payable | 568 |
| | 645 |
| 607 |
| | 568 |
|
Accrued expenses | 327 |
| | 1,250 |
| 373 |
| | 327 |
|
Payables to affiliates | 74 |
| | 65 |
| 119 |
| | 74 |
|
Customer deposits | 112 |
| | 121 |
| 111 |
| | 112 |
|
Regulatory liabilities | 249 |
| | 329 |
| 293 |
| | 249 |
|
Mark-to-market derivative liability | 21 |
| | 19 |
| 26 |
| | 21 |
|
Other | 103 |
| | 84 |
| 96 |
| | 103 |
|
Total current liabilities | 2,294 |
| | 2,938 |
| 1,925 |
| | 2,294 |
|
Long-term debt | 6,761 |
| | 6,608 |
| 7,801 |
| | 6,761 |
|
Long-term debt to financing trust | 205 |
| | 205 |
| 205 |
| | 205 |
|
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 3,469 |
| | 5,364 |
| 3,813 |
| | 3,469 |
|
Asset retirement obligations | 111 |
| | 119 |
| 118 |
| | 111 |
|
Non-pension postretirement benefits obligations | 219 |
| | 239 |
| 201 |
| | 219 |
|
Regulatory liabilities | 6,328 |
| | 3,369 |
| 6,050 |
| | 6,328 |
|
Mark-to-market derivative liability | 235 |
| | 239 |
| 223 |
| | 235 |
|
Other | 562 |
| | 529 |
| 630 |
| | 562 |
|
Total deferred credits and other liabilities | 10,924 |
| | 9,859 |
| 11,035 |
| | 10,924 |
|
Total liabilities | 20,184 |
| | 19,610 |
| 20,966 |
| | 20,184 |
|
Commitments and contingencies | | | |
| |
|
Shareholders’ equity | | | | | | |
Common stock | 1,588 |
| | 1,588 |
| 1,588 |
| | 1,588 |
|
Other paid-in capital | 6,822 |
| | 6,150 |
| 7,322 |
| | 6,822 |
|
Retained deficit unappropriated | (1,639 | ) | | (1,639 | ) | (1,639 | ) | | (1,639 | ) |
Retained earnings appropriated | 2,771 |
| | 2,626 |
| 2,976 |
| | 2,771 |
|
Total shareholders’ equity | 9,542 |
| | 8,725 |
| 10,247 |
| | 9,542 |
|
Total liabilities and shareholders’ equity | $ | 29,726 |
| | $ | 28,335 |
| $ | 31,213 |
| | $ | 29,726 |
|
See the Combined Notes to Consolidated Financial Statements
280225
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
| | (In millions) | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity | Common Stock | | Other Paid-In Capital | | Retained Deficit Unappropriated | | Retained Earnings Appropriated | | Total Shareholders’ Equity |
Balance, December 31, 2014 | $ | 1,588 |
| | $ | 5,468 |
| | $ | (1,639 | ) | | $ | 2,490 |
| | $ | 7,907 |
| |
Net income | — |
| | — |
| | 426 |
| | — |
| | 426 |
| |
Common stock dividends | — |
| | — |
| | — |
| | (299 | ) | | (299 | ) | |
Contribution from parent | — |
| | 202 |
| | — |
| | — |
| | 202 |
| |
Parent tax matter indemnification | — |
| | 7 |
| | — |
| | — |
| | 7 |
| |
Appropriation of retained earnings for future dividends | — |
| | — |
| | (426 | ) | | 426 |
| | — |
| |
Balance, December 31, 2015 | $ | 1,588 |
| | $ | 5,677 |
| | $ | (1,639 | ) | | $ | 2,617 |
| | $ | 8,243 |
| $ | 1,588 |
| | $ | 5,677 |
| | $ | (1,639 | ) | | $ | 2,617 |
| | $ | 8,243 |
|
Net income | — |
| | — |
| | 378 |
| | — |
| | 378 |
| — |
| | — |
| | 378 |
| | — |
| | 378 |
|
Common stock dividends | — |
| | — |
| | — |
| | (369 | ) | | (369 | ) | — |
| | — |
| | — |
| | (369 | ) | | (369 | ) |
Contribution from parent | — |
| | 315 |
| | — |
| | — |
| | 315 |
| — |
| | 315 |
| | — |
| | — |
| | 315 |
|
Parent tax matter indemnification | — |
| | 158 |
| | — |
| | — |
| | 158 |
| — |
| | 158 |
| | — |
| | — |
| | 158 |
|
Appropriation of retained earnings for future dividends | — |
| | — |
| | (378 | ) | | 378 |
| | — |
| — |
| | — |
| | (378 | ) | | 378 |
| | — |
|
Balance, December 31, 2016 | $ | 1,588 |
| | $ | 6,150 |
| | $ | (1,639 | ) | | $ | 2,626 |
| | $ | 8,725 |
| $ | 1,588 |
| | $ | 6,150 |
| | $ | (1,639 | ) | | $ | 2,626 |
| | $ | 8,725 |
|
Net income | — |
| | — |
| | 567 |
| | — |
| | 567 |
| — |
| | — |
| | 567 |
| | — |
| | 567 |
|
Common stock dividends | — |
| | — |
| | — |
| | (422 | ) | | (422 | ) | — |
| | — |
| | — |
| | (422 | ) | | (422 | ) |
Contribution from parent | — |
| | 651 |
| | — |
| | — |
| | 651 |
| |
Contributions from parent | | — |
| | 651 |
| | — |
| | — |
| | 651 |
|
Parent tax matter indemnification | — |
| | 21 |
| | — |
| | — |
| | 21 |
| — |
| | 21 |
| | — |
| | — |
| | 21 |
|
Appropriation of retained earnings for future dividends | — |
| | — |
| | (567 | ) | | 567 |
| | — |
| — |
| | — |
| | (567 | ) | | 567 |
| | — |
|
Balance, December 31, 2017 | $ | 1,588 |
| | $ | 6,822 |
| | $ | (1,639 | ) | | $ | 2,771 |
| | $ | 9,542 |
| $ | 1,588 |
| | $ | 6,822 |
| | $ | (1,639 | ) | | $ | 2,771 |
| | $ | 9,542 |
|
Net income | | — |
| | — |
| | 664 |
| | — |
| | 664 |
|
Common stock dividends | | — |
| | — |
| | — |
| | (459 | ) | | (459 | ) |
Contributions from parent | | — |
| | 500 |
| | — |
| | — |
| | 500 |
|
Appropriation of retained earnings for future dividends | | — |
| | — |
| | (664 | ) | | 664 |
| | — |
|
Balance, December 31, 2018 | | $ | 1,588 |
| | $ | 7,322 |
| | $ | (1,639 | ) | | $ | 2,976 |
| | $ | 10,247 |
|
See the Combined Notes to Consolidated Financial Statements
281226
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 2,369 |
| | $ | 2,524 |
| | $ | 2,485 |
| $ | 2,469 |
| | $ | 2,369 |
| | $ | 2,524 |
|
Natural gas operating revenues | 494 |
| | 462 |
| | 545 |
| 568 |
| | 494 |
| | 462 |
|
Revenues from alternative revenue programs | | (7 | ) | | — |
| | — |
|
Operating revenues from affiliates | 7 |
| | 8 |
| | 2 |
| 8 |
| | 7 |
| | 8 |
|
Total operating revenues | 2,870 |
|
| 2,994 |
|
| 3,032 |
| 3,038 |
|
| 2,870 |
|
| 2,994 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 648 |
| | 598 |
| | 735 |
| 734 |
| | 648 |
| | 598 |
|
Purchased fuel | 186 |
| | 162 |
| | 235 |
| 230 |
| | 186 |
| | 162 |
|
Purchased power from affiliate | 135 |
| | 287 |
| | 220 |
| |
Purchased power from affiliates | | 126 |
| | 135 |
| | 287 |
|
Operating and maintenance | 657 |
| | 665 |
| | 684 |
| 742 |
| | 657 |
| | 665 |
|
Operating and maintenance from affiliates | 149 |
| | 146 |
| | 110 |
| 156 |
| | 149 |
| | 146 |
|
Depreciation and amortization | 286 |
| | 270 |
| | 260 |
| 301 |
| | 286 |
| | 270 |
|
Taxes other than income | 154 |
| | 164 |
| | 160 |
| 163 |
| | 154 |
| | 164 |
|
Total operating expenses | 2,215 |
|
| 2,292 |
|
| 2,404 |
| 2,452 |
|
| 2,215 |
|
| 2,292 |
|
Gain on sales of assets | — |
| | — |
| | 2 |
| 1 |
| | — |
| | — |
|
Operating income | 655 |
|
| 702 |
|
| 630 |
| 587 |
|
| 655 |
|
| 702 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (115 | ) | | (111 | ) | | (102 | ) | (115 | ) | | (115 | ) | | (111 | ) |
Interest expense to affiliates, net | (11 | ) | | (12 | ) | | (12 | ) | (14 | ) | | (11 | ) | | (12 | ) |
Other, net | 9 |
| | 8 |
| | 5 |
| 8 |
| | 9 |
| | 8 |
|
Total other income and (deductions) | (117 | ) |
| (115 | ) |
| (109 | ) | (121 | ) |
| (117 | ) |
| (115 | ) |
Income before income taxes | 538 |
|
| 587 |
|
| 521 |
| 466 |
|
| 538 |
|
| 587 |
|
Income taxes | 104 |
| | 149 |
| | 143 |
| 6 |
| | 104 |
| | 149 |
|
Net income | $ | 434 |
|
| $ | 438 |
|
| $ | 378 |
| $ | 460 |
|
| $ | 434 |
|
| $ | 438 |
|
Comprehensive income | $ | 434 |
|
| $ | 438 |
|
| $ | 378 |
| $ | 460 |
|
| $ | 434 |
|
| $ | 438 |
|
See the Combined Notes to Consolidated Financial Statements
282227
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 434 |
| | $ | 438 |
| | $ | 378 |
| $ | 460 |
| | $ | 434 |
| | $ | 438 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation, amortization and accretion | 286 |
| | 270 |
| | 260 |
| 301 |
| | 286 |
| | 270 |
|
Deferred income taxes and amortization of investment tax credits | 19 |
| | 78 |
| | 90 |
| (5 | ) | | 19 |
| | 78 |
|
Other non-cash operating activities | 54 |
| | 65 |
| | 70 |
| 51 |
| | 54 |
| | 65 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (44 | ) | | (71 | ) | | 37 |
| (74 | ) | | (44 | ) | | (71 | ) |
Receivables from and payables to affiliates, net | (6 | ) | | 6 |
| | 3 |
| 7 |
| | (6 | ) | | 6 |
|
Inventories | 1 |
| | 6 |
| | 10 |
| (14 | ) | | 1 |
| | 6 |
|
Accounts payable and accrued expenses | 6 |
| | 67 |
| | (25 | ) | (3 | ) | | 6 |
| | 67 |
|
Income taxes | 34 |
| | 8 |
| | (9 | ) | 15 |
| | 34 |
| | 8 |
|
Pension and non-pension postretirement benefit contributions | (24 | ) | | (30 | ) | | (40 | ) | (28 | ) | | (24 | ) | | (30 | ) |
Other assets and liabilities | (5 | ) | | (8 | ) | | (4 | ) | 29 |
| | (5 | ) | | (8 | ) |
Net cash flows provided by operating activities | 755 |
|
| 829 |
|
| 770 |
| 739 |
|
| 755 |
|
| 829 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (732 | ) | | (686 | ) | | (601 | ) | (849 | ) | | (732 | ) | | (686 | ) |
Changes in intercompany money pool | 131 |
| | (131 | ) | | — |
| — |
| | 131 |
| | (131 | ) |
Change in restricted cash | — |
| | (1 | ) | | (1 | ) | |
Other investing activities | 4 |
| | 20 |
| | 14 |
| 9 |
| | 4 |
| | 20 |
|
Net cash flows used in investing activities | (597 | ) |
| (798 | ) |
| (588 | ) | (840 | ) |
| (597 | ) |
| (797 | ) |
Cash flows from financing activities | | | | | | | | | | |
Issuance of long-term debt | 325 |
| | 300 |
| | 350 |
| 700 |
| | 325 |
| | 300 |
|
Retirement of long-term debt | — |
| | (300 | ) | | — |
| (500 | ) | | — |
| | (300 | ) |
Contributions from parent | 16 |
| | 18 |
| | 16 |
| 89 |
| | 16 |
| | 18 |
|
Dividends paid on common stock | (288 | ) | | (277 | ) | | (279 | ) | (306 | ) | | (288 | ) | | (277 | ) |
Other financing activities | (3 | ) | | (4 | ) | | (4 | ) | (22 | ) | | (3 | ) | | (4 | ) |
Net cash flows provided by (used in) financing activities | 50 |
|
| (263 | ) |
| 83 |
| |
Increase (Decrease) in cash and cash equivalents | 208 |
| | (232 | ) | | 265 |
| |
Cash and cash equivalents at beginning of period | 63 |
| | 295 |
| | 30 |
| |
Cash and cash equivalents at end of period | $ | 271 |
|
| $ | 63 |
|
| $ | 295 |
| |
Net cash flows (used in) provided by financing activities | | (39 | ) |
| 50 |
|
| (263 | ) |
(Decrease) increase in cash, cash equivalents and restricted cash | | (140 | ) | | 208 |
| | (231 | ) |
Cash, cash equivalents and restricted cash at beginning of period | | 275 |
| | 67 |
| | 298 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 135 |
|
| $ | 275 |
|
| $ | 67 |
|
See the Combined Notes to Consolidated Financial Statements
283228
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 271 |
| | $ | 63 |
| $ | 130 |
| | $ | 271 |
|
Restricted cash and cash equivalents | 4 |
| | 4 |
| 5 |
| | 4 |
|
Accounts receivable, net | | | | | | |
Customer | 327 |
| | 306 |
| 321 |
| | 327 |
|
Other | 105 |
| | 131 |
| 151 |
| | 105 |
|
Receivables from affiliates | — |
| | 4 |
| |
Receivable from Exelon intercompany pool | — |
| | 131 |
| |
Inventories, net | | | | | | |
Fossil fuel | 31 |
| | 35 |
| 38 |
| | 31 |
|
Materials and supplies | 30 |
| | 27 |
| 37 |
| | 30 |
|
Prepaid utility taxes | 8 |
| | 9 |
| — |
| | 8 |
|
Regulatory assets | 29 |
| | 29 |
| 81 |
| | 29 |
|
Other | 17 |
| | 18 |
| 19 |
| | 17 |
|
Total current assets | 822 |
|
| 757 |
| 782 |
|
| 822 |
|
Property, plant and equipment, net | 8,053 |
| | 7,565 |
| 8,610 |
| | 8,053 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 381 |
| | 1,681 |
| 460 |
| | 381 |
|
Investments | 25 |
| | 25 |
| 25 |
| | 25 |
|
Receivable from affiliates | 537 |
| | 438 |
| |
Receivables from affiliates | | 389 |
| | 537 |
|
Prepaid pension asset | 340 |
| | 345 |
| 349 |
| | 340 |
|
Other | 12 |
| | 20 |
| 27 |
| | 12 |
|
Total deferred debits and other assets | 1,295 |
|
| 2,509 |
| 1,250 |
|
| 1,295 |
|
Total assets | $ | 10,170 |
|
| $ | 10,831 |
| $ | 10,642 |
|
| $ | 10,170 |
|
See the Combined Notes to Consolidated Financial Statements
284229
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | |
Current liabilities | | | | | | |
Long-term debt due within one year | $ | 500 |
| | $ | — |
| $ | — |
| | $ | 500 |
|
Accounts payable | 370 |
| | 342 |
| 370 |
| | 370 |
|
Accrued expenses | 114 |
| | 104 |
| 113 |
| | 114 |
|
Payables to affiliates | 53 |
| | 63 |
| 59 |
| | 53 |
|
Customer deposits | 66 |
| | 61 |
| 68 |
| | 66 |
|
Regulatory liabilities | 141 |
| | 127 |
| 175 |
| | 141 |
|
Other | 23 |
| | 30 |
| 24 |
| | 23 |
|
Total current liabilities | 1,267 |
|
| 727 |
| 809 |
|
| 1,267 |
|
Long-term debt | 2,403 |
| | 2,580 |
| 3,084 |
| | 2,403 |
|
Long-term debt to financing trusts | 184 |
| | 184 |
| 184 |
| | 184 |
|
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 1,789 |
| | 3,006 |
| 1,933 |
| | 1,789 |
|
Asset retirement obligations | 27 |
| | 28 |
| 27 |
| | 27 |
|
Non-pension postretirement benefits obligations | 288 |
| | 289 |
| 288 |
| | 288 |
|
Regulatory liabilities | 549 |
| | 517 |
| 421 |
| | 549 |
|
Other | 86 |
| | 85 |
| 76 |
| | 86 |
|
Total deferred credits and other liabilities | 2,739 |
|
| 3,925 |
| 2,745 |
|
| 2,739 |
|
Total liabilities | 6,593 |
|
| 7,416 |
| 6,822 |
|
| 6,593 |
|
Commitments and contingencies | | | |
| |
|
Shareholder's equity | | | | | | |
Common stock | 2,489 |
| | 2,473 |
| 2,578 |
| | 2,489 |
|
Retained earnings | 1,087 |
| | 941 |
| 1,242 |
| | 1,087 |
|
Accumulated other comprehensive income, net | 1 |
| | 1 |
| — |
| | 1 |
|
Total shareholder's equity | 3,577 |
|
| 3,415 |
| 3,820 |
|
| 3,577 |
|
Total liabilities and shareholder's equity | $ | 10,170 |
|
| $ | 10,831 |
| $ | 10,642 |
|
| $ | 10,170 |
|
See the Combined Notes to Consolidated Financial Statements
285230
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
| | (In millions) | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income | | Total Shareholder's Equity | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income | | Total Shareholder's Equity |
Balance, December 31, 2014 | $ | 2,439 |
| | $ | 681 |
| | $ | 1 |
| | $ | 3,121 |
| |
Net income | — |
| | 378 |
| | — |
| | 378 |
| |
Common stock dividends | — |
| | (279 | ) | | — |
| | (279 | ) | |
Allocation of tax benefit from parent | 16 |
| | — |
| | — |
| | 16 |
| |
Balance, December 31, 2015 | $ | 2,455 |
|
| $ | 780 |
|
| $ | 1 |
|
| $ | 3,236 |
| $ | 2,455 |
| | $ | 780 |
| | $ | 1 |
| | $ | 3,236 |
|
Net income | — |
| | 438 |
| | — |
| | 438 |
| — |
| | 438 |
| | — |
| | 438 |
|
Common stock dividends | — |
| | (277 | ) | | — |
| | (277 | ) | — |
| | (277 | ) | | — |
| | (277 | ) |
Allocation of tax benefit from parent | 18 |
| | — |
| | — |
| | 18 |
| |
Contributions from parent | | 18 |
| | — |
| | — |
| | 18 |
|
Balance, December 31, 2016 | $ | 2,473 |
|
| $ | 941 |
|
| $ | 1 |
|
| $ | 3,415 |
| $ | 2,473 |
|
| $ | 941 |
|
| $ | 1 |
|
| $ | 3,415 |
|
Net income | — |
| | 434 |
| | — |
| | 434 |
| — |
| | 434 |
| | — |
| | 434 |
|
Common stock dividends | — |
| | (288 | ) | | — |
| | (288 | ) | — |
| | (288 | ) | | — |
| | (288 | ) |
Allocation of tax benefit from parent | 16 |
| | — |
| | — |
| | 16 |
| |
Contributions from parent | | 16 |
| | — |
| | — |
| | 16 |
|
Balance, December 31, 2017 | $ | 2,489 |
|
| $ | 1,087 |
|
| $ | 1 |
|
| $ | 3,577 |
| $ | 2,489 |
|
| $ | 1,087 |
|
| $ | 1 |
|
| $ | 3,577 |
|
Net income | | — |
| | 460 |
| | — |
| | 460 |
|
Common stock dividends | | — |
| | (306 | ) | | — |
| | (306 | ) |
Contributions from parent | | 89 |
| | — |
| | — |
| | 89 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Liabilities standard | | — |
| | 1 |
| | (1 | ) | | — |
|
Balance, December 31, 2018 | | $ | 2,578 |
|
| $ | 1,242 |
|
| $ | — |
|
| $ | 3,820 |
|
See the Combined Notes to Consolidated Financial Statements
286231
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 2,484 |
| | $ | 2,603 |
| | $ | 2,490 |
| $ | 2,428 |
| | $ | 2,384 |
| | $ | 2,531 |
|
Natural gas operating revenues | 676 |
| | 609 |
| | 631 |
| 738 |
| | 652 |
| | 628 |
|
Revenues from alternative revenue programs | | (26 | ) | | 124 |
| | 53 |
|
Operating revenues from affiliates | 16 |
| | 21 |
| | 14 |
| 29 |
| | 16 |
| | 21 |
|
Total operating revenues | 3,176 |
|
| 3,233 |
|
| 3,135 |
| 3,169 |
|
| 3,176 |
|
| 3,233 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 566 |
| | 528 |
| | 602 |
| 671 |
| | 566 |
| | 528 |
|
Purchased fuel | 183 |
| | 162 |
| | 205 |
| 254 |
| | 183 |
| | 162 |
|
Purchased power from affiliate | 384 |
| | 604 |
| | 498 |
| |
Purchased power from affiliates | | 257 |
| | 384 |
| | 604 |
|
Operating and maintenance | 563 |
| | 605 |
| | 565 |
| 615 |
| | 563 |
| | 605 |
|
Operating and maintenance from affiliates | 153 |
| | 132 |
| | 118 |
| 162 |
| | 153 |
| | 132 |
|
Depreciation and amortization | 473 |
| | 423 |
| | 366 |
| 483 |
| | 473 |
| | 423 |
|
Taxes other than income | 240 |
| | 229 |
| | 224 |
| 254 |
| | 240 |
| | 229 |
|
Total operating expenses | 2,562 |
|
| 2,683 |
|
| 2,578 |
| 2,696 |
|
| 2,562 |
|
| 2,683 |
|
Gain on sales of assets | — |
| | — |
| | 1 |
| 1 |
| | — |
| | — |
|
Operating income | 614 |
|
| 550 |
|
| 558 |
| 474 |
|
| 614 |
|
| 550 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (95 | ) | | (87 | ) | | (83 | ) | (106 | ) | | (95 | ) | | (87 | ) |
Interest expense to affiliates | (10 | ) | | (16 | ) | | (16 | ) | — |
| | (10 | ) | | (16 | ) |
Other, net | 16 |
| | 21 |
| | 18 |
| 19 |
| | 16 |
| | 21 |
|
Total other income and (deductions) | (89 | ) |
| (82 | ) |
| (81 | ) | (87 | ) |
| (89 | ) |
| (82 | ) |
Income before income taxes | 525 |
| | 468 |
| | 477 |
| 387 |
| | 525 |
| | 468 |
|
Income taxes | 218 |
| | 174 |
| | 189 |
| 74 |
| | 218 |
| | 174 |
|
Net income | 307 |
|
| 294 |
|
| 288 |
| 313 |
|
| 307 |
|
| 294 |
|
Preference stock dividends | — |
| | 8 |
| | 13 |
| — |
| | — |
| | 8 |
|
Net income attributable to common shareholder | $ | 307 |
|
| $ | 286 |
|
| $ | 275 |
| $ | 313 |
|
| $ | 307 |
|
| $ | 286 |
|
| | | | | | | | | | |
Comprehensive income | $ | 307 |
|
| $ | 294 |
|
| $ | 288 |
| $ | 313 |
|
| $ | 307 |
|
| $ | 294 |
|
Comprehensive income attributable to preference stock dividends | — |
| | 8 |
| | 13 |
| — |
| | — |
| | 8 |
|
Comprehensive income attributable to common shareholder | $ | 307 |
| | $ | 286 |
| | $ | 275 |
| $ | 313 |
| | $ | 307 |
| | $ | 286 |
|
See the Combined Notes to Consolidated Financial Statements
287232
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 307 |
| | $ | 294 |
| | $ | 288 |
| $ | 313 |
| | $ | 307 |
| | $ | 294 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation and amortization | 473 |
| | 423 |
| | 366 |
| 483 |
| | 473 |
| | 423 |
|
Impairment losses on long-lived assets and regulatory assets | 7 |
| | 52 |
| | — |
| — |
| | 7 |
| | 52 |
|
Deferred income taxes and amortization of investment tax credits | 145 |
| | 118 |
| | 165 |
| 76 |
| | 145 |
| | 118 |
|
Other non-cash operating activities | 65 |
| | 88 |
| | 137 |
| 58 |
| | 65 |
| | 88 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (5 | ) | | (98 | ) | | 84 |
| 8 |
| | (5 | ) | | (98 | ) |
Receivables from and payables to affiliates, net | (4 | ) | | 3 |
| | (2 | ) | 12 |
| | (4 | ) | | 3 |
|
Inventories | (9 | ) | | 1 |
| | 18 |
| 2 |
| | (9 | ) | | 1 |
|
Accounts payable and accrued expenses | (15 | ) | | 138 |
| | (3 | ) | (1 | ) | | (15 | ) | | 138 |
|
Collateral received (posted), net | — |
| | — |
| | (27 | ) | |
Collateral received, net | | 4 |
| | — |
| | — |
|
Income taxes | 60 |
| | 18 |
| | (54 | ) | (20 | ) | | 60 |
| | 18 |
|
Pension and non-pension postretirement benefit contributions | (53 | ) | | (49 | ) | | (17 | ) | (54 | ) | | (53 | ) | | (49 | ) |
Other assets and liabilities | (150 | ) | | (43 | ) | | (173 | ) | (92 | ) | | (150 | ) | | (43 | ) |
Net cash flows provided by operating activities | 821 |
|
| 945 |
|
| 782 |
| 789 |
|
| 821 |
|
| 945 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (882 | ) | | (934 | ) | | (719 | ) | (959 | ) | | (882 | ) | | (934 | ) |
Change in restricted cash | 26 |
| | — |
| | 26 |
| |
Other investing activities | 7 |
| | 24 |
| | 18 |
| 9 |
| | 7 |
| | 24 |
|
Net cash flows used in investing activities | (849 | ) |
| (910 | ) |
| (675 | ) | (950 | ) |
| (875 | ) |
| (910 | ) |
Cash flows from financing activities | | | | | | | | | | |
Changes in short-term borrowings | 32 |
| | (165 | ) | | 90 |
| (42 | ) | | 32 |
| | (165 | ) |
Issuance of long-term debt | 300 |
| | 850 |
| | — |
| 300 |
| | 300 |
| | 850 |
|
Retirement of long-term debt | (41 | ) | | (379 | ) | | (75 | ) | — |
| | (41 | ) | | (379 | ) |
Retirement of long-term debt to financing trust | (250 | ) | | — |
| | — |
| — |
| | (250 | ) | | — |
|
Redemption of preference stock | — |
| | (190 | ) | | — |
| — |
| | — |
| | (190 | ) |
Dividends paid on preference stock | — |
| | (8 | ) | | (13 | ) | — |
| | — |
| | (8 | ) |
Dividends paid on common stock | (198 | ) | | (179 | ) | | (158 | ) | (209 | ) | | (198 | ) | | (179 | ) |
Contributions from parent | 184 |
| | 61 |
| | 7 |
| 109 |
| | 184 |
| | 61 |
|
Other financing activities | (5 | ) | | (11 | ) | | (13 | ) | (2 | ) | | (5 | ) | | (11 | ) |
Net cash flows provided by (used in) financing activities | 22 |
|
| (21 | ) |
| (162 | ) | 156 |
|
| 22 |
|
| (21 | ) |
(Decrease) Increase in cash and cash equivalents | (6 | ) | | 14 |
| | (55 | ) | |
Cash and cash equivalents at beginning of period | 23 |
| | 9 |
| | 64 |
| |
Cash and cash equivalents at end of period | $ | 17 |
|
| $ | 23 |
|
| $ | 9 |
| |
(Decrease) increase in cash, cash equivalents and restricted cash | | (5 | ) | | (32 | ) | | 14 |
|
Cash, cash equivalents and restricted cash at beginning of period | | 18 |
| | 50 |
| | 36 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 13 |
|
| $ | 18 |
|
| $ | 50 |
|
See the Combined Notes to Consolidated Financial Statements
288233
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 |
| 2016 | 2018 |
| 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 17 |
| | $ | 23 |
| $ | 7 |
| | $ | 17 |
|
Restricted cash and cash equivalents | 1 |
| | 24 |
| 6 |
| | 1 |
|
Accounts receivable, net | | | | | | |
Customer | 375 |
| | 395 |
| 353 |
| | 375 |
|
Other | 94 |
| | 102 |
| 90 |
| | 94 |
|
Receivable from affiliates | 1 |
| | — |
| |
Receivables from affiliates | | 1 |
| | 1 |
|
Inventories, net | | | | | | |
Gas held in storage | 37 |
| | 30 |
| 36 |
| | 37 |
|
Materials and supplies | 40 |
| | 38 |
| 39 |
| | 40 |
|
Prepaid utility taxes | 69 |
| | 15 |
| 74 |
| | 69 |
|
Regulatory assets | 174 |
| | 208 |
| 177 |
| | 174 |
|
Other | 3 |
| | 7 |
| 3 |
| | 3 |
|
Total current assets | 811 |
|
| 842 |
| 786 |
|
| 811 |
|
Property, plant and equipment, net | 7,602 |
| | 7,040 |
| 8,243 |
| | 7,602 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 397 |
| | 504 |
| 398 |
| | 397 |
|
Investments | 5 |
| | 12 |
| 5 |
| | 5 |
|
Prepaid pension asset | 285 |
| | 297 |
| 279 |
| | 285 |
|
Other | 4 |
| | 9 |
| 5 |
| | 4 |
|
Total deferred debits and other assets | 691 |
|
| 822 |
| 687 |
|
| 691 |
|
Total assets(a) | $ | 9,104 |
|
| $ | 8,704 |
| $ | 9,716 |
|
| $ | 9,104 |
|
See the Combined Notes to Consolidated Financial Statements
289234
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 77 |
| | $ | 45 |
| $ | 35 |
| | $ | 77 |
|
Long-term debt due within one year | — |
| | 41 |
| |
Accounts payable | 265 |
| | 205 |
| 295 |
| | 265 |
|
Accrued expenses | 164 |
| | 175 |
| 155 |
| | 164 |
|
Payables to affiliates | 52 |
| | 55 |
| 65 |
| | 52 |
|
Customer deposits | 116 |
| | 110 |
| 120 |
| | 116 |
|
Regulatory liabilities | 62 |
| | 50 |
| 77 |
| | 62 |
|
Other | 24 |
| | 26 |
| 27 |
| | 24 |
|
Total current liabilities | 760 |
|
| 707 |
| 774 |
|
| 760 |
|
Long-term debt | 2,577 |
| | 2,281 |
| 2,876 |
| | 2,577 |
|
Long-term debt to financing trust | — |
| | 252 |
| |
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 1,244 |
| | 2,219 |
| 1,222 |
| | 1,244 |
|
Asset retirement obligations | 23 |
| | 21 |
| 24 |
| | 23 |
|
Non-pension postretirement benefits obligations | 202 |
| | 205 |
| 201 |
| | 202 |
|
Regulatory liabilities | 1,101 |
| | 110 |
| 1,192 |
| | 1,101 |
|
Other | 56 |
| | 61 |
| 73 |
| | 56 |
|
Total deferred credits and other liabilities | 2,626 |
|
| 2,616 |
| 2,712 |
|
| 2,626 |
|
Total liabilities(a) | 5,963 |
|
| 5,856 |
| |
Total liabilities | | 6,362 |
|
| 5,963 |
|
Commitments and contingencies | | | |
| |
|
Shareholder's equity | | | | | | |
Common stock | 1,605 |
| | 1,421 |
| 1,714 |
| | 1,605 |
|
Retained earnings | 1,536 |
| | 1,427 |
| 1,640 |
| | 1,536 |
|
Total shareholder's equity | 3,141 |
|
| 2,848 |
| 3,354 |
|
| 3,141 |
|
Total liabilities and shareholder's equity | $ | 9,104 |
|
| $ | 8,704 |
| $ | 9,716 |
|
| $ | 9,104 |
|
__________
| |
(a) | BGE’s consolidated assets include $26 million at December 31, 2016 of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million at December 31, 2016 of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. BGE no longer has interests in any VIEs as of December 31, 2017. See Note 2 - Variable Interest Entities. |
See the Combined Notes to Consolidated Financial Statements
290235
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
| | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | | Preference stock not subject to mandatory redemption | | Total Equity | Common Stock | | Retained Earnings | | Total Shareholder's Equity | | Preference stock not subject to mandatory redemption | | Total Equity |
Balance, December 31, 2014 | $ | 1,360 |
| | $ | 1,203 |
| | $ | 2,563 |
| | $ | 190 |
| | $ | 2,753 |
| |
Net income | — |
| | 288 |
| | 288 |
| | — |
| | 288 |
| |
Preference stock dividends | — |
| | (13 | ) | | (13 | ) | | — |
| | (13 | ) | |
Common stock dividends | — |
| | (158 | ) | | (158 | ) | | — |
| | (158 | ) | |
Contribution from parent | 7 |
| | — |
| | 7 |
| | — |
| | 7 |
| |
Balance, December 31, 2015 | $ | 1,367 |
|
| $ | 1,320 |
|
| $ | 2,687 |
|
| $ | 190 |
|
| $ | 2,877 |
| $ | 1,367 |
| | $ | 1,320 |
| | $ | 2,687 |
| | $ | 190 |
| | $ | 2,877 |
|
Net income | — |
| | 294 |
| | 294 |
| | — |
| | 294 |
| — |
| | 294 |
| | 294 |
| | — |
| | 294 |
|
Preference stock dividends | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) | — |
| | (8 | ) | | (8 | ) | | — |
| | (8 | ) |
Common stock dividends | — |
| | (179 | ) | | (179 | ) | | — |
| | (179 | ) | — |
| | (179 | ) | | (179 | ) | | — |
| | (179 | ) |
Distribution to parent | (7 | ) | | — |
| | (7 | ) | | — |
| | (7 | ) | |
Contribution from parent | 61 |
| | — |
| | 61 |
| | — |
| | 61 |
| |
Distributions to parent | | (7 | ) | | — |
| | (7 | ) | |
|
| | (7 | ) |
Contributions from parent | | 61 |
| | — |
| | 61 |
| | — |
| | 61 |
|
Redemption of preference stock | — |
| | — |
| | — |
| | (190 | ) | | (190 | ) | — |
| | — |
| | — |
| | (190 | ) | | (190 | ) |
Balance, December 31, 2016 | $ | 1,421 |
|
| $ | 1,427 |
|
| $ | 2,848 |
|
| $ | — |
|
| $ | 2,848 |
| $ | 1,421 |
|
| $ | 1,427 |
|
| $ | 2,848 |
|
| $ | — |
|
| $ | 2,848 |
|
Net income | — |
| | 307 |
| | 307 |
| | — |
| | 307 |
| — |
| | 307 |
| | 307 |
| | — |
| | 307 |
|
Common stock dividends | — |
| | (198 | ) | | (198 | ) | | — |
| | (198 | ) | — |
| | (198 | ) | | (198 | ) | | — |
| | (198 | ) |
Contribution from parent | 184 |
| | — |
| | 184 |
| | — |
| | 184 |
| |
Contributions from parent | | 184 |
| | — |
| | 184 |
| | — |
| | 184 |
|
Balance, December 31, 2017 | $ | 1,605 |
|
| $ | 1,536 |
|
| $ | 3,141 |
|
| $ | — |
|
| $ | 3,141 |
| $ | 1,605 |
|
| $ | 1,536 |
|
| $ | 3,141 |
|
| $ | — |
|
| $ | 3,141 |
|
Net income | | — |
| | 313 |
| | 313 |
| | — |
| | 313 |
|
Common stock dividends | | — |
| | (209 | ) | | (209 | ) | | — |
| | (209 | ) |
Contributions from parent | | 109 |
| | — |
| | 109 |
| | — |
| | 109 |
|
Balance, December 31, 2018 | | $ | 1,714 |
|
| $ | 1,640 |
|
| $ | 3,354 |
|
| $ | — |
|
| $ | 3,354 |
|
See the Combined Notes to Consolidated Financial Statements
291236
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income (Loss)
| | | Successor | | | Predecessor | Successor | | | Predecessor |
| For the Year Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, | | For the Year Ended December 31, | For the Years Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, |
(In millions)
| 2017 | | 2016 | | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | | 2016 |
Operating revenues | | | | | | | | | | | | | | | | |
Electric operating revenues | $ | 4,468 |
| | $ | 3,506 |
| | | $ | 1,096 |
| | $ | 4,770 |
| $ | 4,609 |
| | $ | 4,428 |
| | $ | 3,463 |
| | | $ | 1,122 |
|
Natural gas operating revenues | 161 |
| | 92 |
| | | 57 |
| | 165 |
| 181 |
| | 161 |
| | 92 |
| | | 57 |
|
Revenues from alternative revenue programs | | — |
| | 40 |
| | 43 |
| | | (26 | ) |
Operating revenues from affiliates | 50 |
| | 45 |
| | | — |
| | — |
| 15 |
| | 50 |
| | 45 |
| | | — |
|
Total operating revenues | 4,679 |
|
| 3,643 |
| | | 1,153 |
| | 4,935 |
| 4,805 |
|
| 4,679 |
| | 3,643 |
| | | 1,153 |
|
Operating expenses | | | | | | | | | | | | | | | | |
Purchased power | 1,182 |
| | 925 |
| | | 471 |
| | 1,986 |
| 1,387 |
| | 1,182 |
| | 925 |
| | | 471 |
|
Purchased fuel | 71 |
| | 36 |
| | | 26 |
| | 87 |
| 89 |
| | 71 |
| | 36 |
| | | 26 |
|
Purchased power and fuel from affiliates | 463 |
| | 486 |
| | | — |
| | — |
| |
Purchased power from affiliates | | 355 |
| | 463 |
| | 486 |
| | | — |
|
Operating and maintenance | 918 |
| | 1,144 |
| | | 294 |
| | 1,156 |
| 978 |
| | 918 |
| | 1,144 |
| | | 294 |
|
Operating and maintenance from affiliates | 150 |
| | 89 |
| | | — |
| | — |
| 152 |
| | 150 |
| | 89 |
| | | — |
|
Depreciation, amortization and accretion | 675 |
| | 515 |
| | | 152 |
| | 624 |
| 740 |
| | 675 |
| | 515 |
| | | 152 |
|
Taxes other than income | 452 |
| | 354 |
| | | 105 |
| | 455 |
| 455 |
| | 452 |
| | 354 |
| | | 105 |
|
Total operating expenses | 3,911 |
|
| 3,549 |
| | | 1,048 |
| | 4,308 |
| 4,156 |
|
| 3,911 |
| | 3,549 |
| | | 1,048 |
|
Gain (loss) on sales of assets | 1 |
| | (1 | ) | | | — |
| | 46 |
| 1 |
| | 1 |
| | (1 | ) | | | — |
|
Operating income | 769 |
|
| 93 |
| | | 105 |
| | 673 |
| 650 |
|
| 769 |
| | 93 |
| | | 105 |
|
Other income and (deductions) | | | | | | | | | | | | | | | | |
Interest expense, net | (245 | ) | | (195 | ) | | | (65 | ) | | (280 | ) | (261 | ) | | (245 | ) | | (195 | ) | | | (65 | ) |
Other, net | 54 |
| | 44 |
| | | (4 | ) | | 88 |
| 43 |
| | 54 |
| | 44 |
| | | (4 | ) |
Total other income and (deductions) | (191 | ) | | (151 | ) | | | (69 | ) | | (192 | ) | (218 | ) | | (191 | ) | | (151 | ) | | | (69 | ) |
Income (loss) before income taxes | 578 |
|
| (58 | ) | | | 36 |
| | 481 |
| 432 |
|
| 578 |
| | (58 | ) | | | 36 |
|
Income taxes | 217 |
| | 3 |
| | | 17 |
| | 163 |
| 35 |
| | 217 |
| | 3 |
| | | 17 |
|
Equity in earnings of unconsolidated affiliates
| 1 |
| | — |
| | | — |
| | — |
| 1 |
| | 1 |
| | — |
| | | — |
|
Net income (loss) from continuing operations | 362 |
| | (61 | ) | | | 19 |
| | 318 |
| |
Net income from discontinued operations | — |
| | — |
| | | — |
| | 9 |
| |
Net income (loss) | | 398 |
| | 362 |
| | (61 | ) | | | 19 |
|
Net income (loss) attributable to membership interest/common shareholders | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
| | $ | 327 |
| $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
Comprehensive income (loss), net of income taxes | | | | | | | | | | | | | | | | |
Net income (loss) | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
| | $ | 327 |
| $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
Other comprehensive income (loss), net of income taxes | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | | | | | | | | | | |
Actuarial loss reclassified to periodic cost | — |
| | — |
| | | 1 |
| | 9 |
| — |
| | — |
| | — |
| | | 1 |
|
Unrealized loss on cash flow hedges | — |
| | — |
| | | — |
| | 1 |
| |
Other comprehensive income | — |
| | — |
| | | 1 |
| | 10 |
| — |
| | — |
| | — |
| | | 1 |
|
Comprehensive income (loss) | $ | 362 |
| | $ | (61 | ) | | | $ | 20 |
| | $ | 337 |
| $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 20 |
|
See the Combined Notes to Consolidated Financial Statements
292237
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
| | | Successor | | | Predecessor | Successor | | | Predecessor |
| For the Year Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, | | For the Year Ended December 31, | For the Years Ended December 31, | | March 24 to December 31, | | | January 1 to March 23, |
(In millions) | 2017 | | 2016 | | | 2016 | | 2015 | 2018 | | 2017 | | 2016 | | | 2016 |
Cash flows from operating activities | | | | | | | | | | | | | | | | |
Net income (loss) | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
| | $ | 327 |
| $ | 398 |
| | $ | 362 |
| | $ | (61 | ) | | | $ | 19 |
|
Income from discontinued operations, net of income taxes | — |
| | — |
| | | — |
| | (9 | ) | |
Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | | | | | | | | | | | | |
Depreciation and amortization | 675 |
| | 515 |
| | | 152 |
| | 624 |
| 740 |
| | 675 |
| | 515 |
| | | 152 |
|
Impairment losses on intangibles and regulatory assets | 52 |
| | — |
| | | — |
| | — |
| — |
| | 52 |
| | — |
| | | — |
|
(Gain) loss on sales of assets | (1 | ) | | 1 |
| | | — |
| | (46 | ) | |
Deferred income taxes and amortization of investment tax credits | 252 |
| | 295 |
| | | 19 |
| | 134 |
| 32 |
| | 252 |
| | 295 |
| | | 19 |
|
Net fair value changes related to derivatives | — |
| | — |
| | | 18 |
| | — |
| — |
| | — |
| | — |
| | | 18 |
|
Other non-cash operating activities | 59 |
| | 514 |
| | | 46 |
| | 167 |
| 143 |
| | 58 |
| | 515 |
| | | 46 |
|
Changes in assets and liabilities: | | | | | | | | | | | | | | | | |
Accounts receivable | (26 | ) | | (21 | ) | | | (28 | ) | | (105 | ) | (2 | ) | | (26 | ) | | (21 | ) | | | (28 | ) |
Receivables from and payables to affiliates, net | (2 | ) | | 42 |
| | | — |
| | — |
| 8 |
| | (2 | ) | | 42 |
| | | — |
|
Inventories | (37 | ) | | 3 |
| | | (4 | ) | | — |
| (14 | ) | | (37 | ) | | 3 |
| | | (4 | ) |
Accounts payable and accrued expenses | (106 | ) | | 19 |
| | | 42 |
| | (41 | ) | 45 |
| | (106 | ) | | 19 |
| | | 42 |
|
Income taxes | 79 |
| | (22 | ) | | | 12 |
| | 8 |
| 34 |
| | 79 |
| | (22 | ) | | | 12 |
|
Pension and non-pension postretirement benefit contributions | (99 | ) | | (86 | ) | | | (4 | ) | | (21 | ) | (74 | ) | | (99 | ) | | (86 | ) | | | (4 | ) |
Other assets and liabilities | (258 | ) | | (311 | ) | | | (8 | ) | | (99 | ) | (178 | ) | | (258 | ) | | (311 | ) | | | (8 | ) |
Net cash flows provided by operating activities | 950 |
| | 888 |
| | | 264 |
| | 939 |
| 1,132 |
| | 950 |
| | 888 |
| | | 264 |
|
Cash flows from investing activities | | | | | | | | | | | | | | | | |
Capital expenditures | (1,396 | ) | | (1,008 | ) | | | (273 | ) | | (1,230 | ) | (1,375 | ) | | (1,396 | ) | | (1,008 | ) | | | (273 | ) |
Proceeds from sales of long-lived assets | 1 |
| | 24 |
| | | — |
| | 54 |
| |
Changes in restricted cash | 1 |
| | (37 | ) | | | 3 |
| | 6 |
| |
Purchases of investments | — |
| | — |
| | | (68 | ) | | — |
| — |
| | — |
| | — |
| | | (68 | ) |
Other investing activities | (2 | ) | | (9 | ) | | | (5 | ) | | 9 |
| 4 |
| | (1 | ) | | 15 |
| | | (5 | ) |
Net cash flows used in investing activities | (1,396 | ) | | (1,030 | ) | | | (343 | ) | | (1,161 | ) | (1,371 | ) | | (1,397 | ) | | (993 | ) | | | (346 | ) |
Cash flows from financing activities | | | | | | | | | | | | | | | | |
Changes in short-term borrowings | 328 |
| | (515 | ) | | | (121 | ) | | 34 |
| (296 | ) | | 328 |
| | (515 | ) | | | (121 | ) |
Proceeds from short-term borrowings with maturities greater than 90 days | — |
| | — |
| | | 500 |
| | 300 |
| 125 |
| | — |
| | — |
| | | 500 |
|
Repayments of short-term borrowings with maturities greater than 90 days | (500 | ) | | (300 | ) | | | — |
| | — |
| — |
| | (500 | ) | | (300 | ) | | | — |
|
Issuance of long-term debt | 202 |
| | 179 |
| | | — |
| | 558 |
| 750 |
| | 202 |
| | 179 |
| | | — |
|
Retirement of long-term debt | (169 | ) | | (338 | ) | | | (11 | ) | | (430 | ) | (299 | ) | | (169 | ) | | (338 | ) | | | (11 | ) |
Issuance of preferred stock | — |
| | — |
| | | — |
| | 54 |
| |
Dividends paid on common stock | — |
| | — |
| | | — |
| | (275 | ) | |
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation | — |
| | — |
| | | 2 |
| | 18 |
| — |
| | — |
| | — |
| | | 2 |
|
Distribution to member | (311 | ) | | (273 | ) | | | — |
| | — |
| |
Distributions to member | | (326 | ) | | (311 | ) | | (273 | ) | | | — |
|
Contributions from member | 758 |
| | 1,251 |
| | | — |
| | — |
| 385 |
| | 758 |
| | 1,251 |
| | | — |
|
Change in Exelon intercompany money pool | — |
| | (6 | ) | | | — |
| | — |
| — |
| | — |
| | (6 | ) | | | — |
|
Other financing activities | (2 | ) | | (5 | ) | | | 2 |
| | (26 | ) | (9 | ) | | (2 | ) | | (5 | ) | | | 2 |
|
Net cash flows provided by (used in) financing activities | 306 |
| | (7 | ) | | | 372 |
| | 233 |
| 330 |
| | 306 |
| | (7 | ) | | | 372 |
|
(Decrease) Increase in cash and cash equivalents | (140 | ) | | (149 | ) | |
| 293 |
|
| 11 |
| |
Cash and cash equivalents at beginning of period | 170 |
| | 319 |
| | | 26 |
| | 15 |
| |
Cash and cash equivalents at end of period | $ | 30 |
| | $ | 170 |
| |
| $ | 319 |
|
| $ | 26 |
| |
Increase (decrease) in cash, cash equivalents and restricted cash | | 91 |
| | (141 | ) |
| (112 | ) | |
| 290 |
|
Cash, cash equivalents and restricted cash at beginning of period | | 95 |
| | 236 |
| | 348 |
| | | 58 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 186 |
| | $ | 95 |
|
| $ | 236 |
| |
| $ | 348 |
|
See the Combined Notes to Consolidated Financial Statements
293238
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | Successor | | | | | |
| December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 30 |
| | $ | 170 |
| $ | 124 |
| | $ | 30 |
|
Restricted cash and cash equivalents | 42 |
| | 43 |
| 43 |
| | 42 |
|
Accounts receivable, net | | | | | | |
Customer | 486 |
| | 496 |
| 453 |
| | 486 |
|
Other | 206 |
| | 283 |
| 177 |
| | 206 |
|
Inventories, net | | | | | | |
Gas held in storage | 7 |
| | 6 |
| 9 |
| | 7 |
|
Materials and supplies | 151 |
| | 116 |
| 163 |
| | 151 |
|
Regulatory assets | 554 |
| | 653 |
| 489 |
| | 554 |
|
Other | 75 |
| | 71 |
| 75 |
| | 75 |
|
Total current assets | 1,551 |
| | 1,838 |
| 1,533 |
| | 1,551 |
|
Property, plant and equipment, net | 12,498 |
| | 11,598 |
| 13,446 |
| | 12,498 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 2,493 |
| | 2,851 |
| 2,312 |
| | 2,493 |
|
Investments | 132 |
| | 133 |
| 130 |
| | 132 |
|
Goodwill | 4,005 |
| | 4,005 |
| 4,005 |
| | 4,005 |
|
Long-term note receivable | 4 |
| | 4 |
| — |
| | 4 |
|
Prepaid pension asset | 490 |
| | 509 |
| 486 |
| | 490 |
|
Deferred income taxes | 4 |
| | 6 |
| 12 |
| | 4 |
|
Other | 70 |
| | 81 |
| 60 |
| | 70 |
|
Total deferred debits and other assets | 7,198 |
| | 7,589 |
| 7,005 |
| | 7,198 |
|
Total assets(a) | $ | 21,247 |
| | $ | 21,025 |
| $ | 21,984 |
| | $ | 21,247 |
|
See the Combined Notes to Consolidated Financial Statements
294239
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
| | | Successor | | | | | |
| December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 350 |
| | $ | 522 |
| $ | 179 |
| | $ | 350 |
|
Long-term debt due within one year | 396 |
| | 253 |
| 125 |
| | 396 |
|
Accounts payable | 348 |
| | 458 |
| 496 |
| | 348 |
|
Accrued expenses | 261 |
| | 272 |
| 256 |
| | 261 |
|
Payables to affiliates | 90 |
| | 94 |
| 94 |
| | 90 |
|
Regulatory liabilities | | 84 |
| | 56 |
|
Unamortized energy contract liabilities | 188 |
| | 335 |
| 119 |
| | 188 |
|
Customer deposits | 119 |
| | 123 |
| 116 |
| | 119 |
|
Merger related obligation | 42 |
| | 101 |
| |
Regulatory liabilities | 56 |
| | 79 |
| |
Other | 81 |
| | 47 |
| 123 |
| | 123 |
|
Total current liabilities | 1,931 |
| | 2,284 |
| 1,592 |
| | 1,931 |
|
Long-term debt | 5,478 |
| | 5,645 |
| 6,134 |
| | 5,478 |
|
Deferred credits and other liabilities | | | | | | |
Regulatory liabilities | 1,872 |
| | 158 |
| |
Deferred income taxes and unamortized investment tax credits | 2,070 |
| | 3,775 |
| 2,146 |
| | 2,070 |
|
Asset retirement obligations | 16 |
| | 14 |
| 52 |
| | 16 |
|
Non-pension postretirement benefit obligations | 105 |
| | 134 |
| 103 |
| | 105 |
|
Regulatory liabilities | | 1,864 |
| | 1,872 |
|
Unamortized energy contract liabilities | 561 |
| | 750 |
| 442 |
| | 561 |
|
Other | 389 |
| | 249 |
| 369 |
| | 389 |
|
Total deferred credits and other liabilities | 5,013 |
| | 5,080 |
| 4,976 |
| | 5,013 |
|
Total liabilities(a) | 12,422 |
| | 13,009 |
| 12,702 |
| | 12,422 |
|
Commitments and contingencies | | | |
| |
|
Member's equity | | | | | | |
Membership interest | 8,835 |
| | 8,077 |
| 9,220 |
| | 8,835 |
|
Undistributed (losses) | (10 | ) | | (61 | ) | |
Undistributed gains (losses) | | 62 |
| | (10 | ) |
Total member's equity | 8,825 |
| | 8,016 |
| 9,282 |
| | 8,825 |
|
Total liabilities and member's equity | $ | 21,247 |
| | $ | 21,025 |
| $ | 21,984 |
| | $ | 21,247 |
|
_____________
| |
(a) | PHI’s consolidated total assets include $41$33 million and $49$41 million at December 31, 20172018 and 2016,2017, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $102$69 million and $143$102 million at December 31, 20172018 and 2016,2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities.Entities for additional information. |
See the Combined Notes to Consolidated Financial Statements
295240
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
| | (In millions, except share data) | Common Stock(a) | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Total Shareholders' Equity | Common Stock(a) | | Retained Earnings | | Accumulated Other Comprehensive Loss, net | | Total Shareholders' Equity |
Predecessor | | | | | | | | | | | | | | |
Balance, December 31, 2014 | $ | 3,803 |
| | $ | 565 |
| | $ | (46 | ) | | $ | 4,322 |
| |
Net income | — |
| | 327 |
| | — |
| | 327 |
| |
Common stock dividends | — |
| | (275 | ) | | — |
| | (275 | ) | |
Original issue shares, net | 15 |
| | — |
| | — |
| | 15 |
| |
DRP original issue shares | 11 |
| | — |
| | — |
| | 11 |
| |
Net activity related to stock-based awards | 3 |
| | — |
| | — |
| | 3 |
| |
Other comprehensive income, net of income taxes | — |
| | — |
| | 10 |
| | 10 |
| |
Balance, December 31, 2015 | $ | 3,832 |
|
| $ | 617 |
|
| $ | (36 | ) |
| $ | 4,413 |
| $ | 3,832 |
| | $ | 617 |
| | $ | (36 | ) | | $ | 4,413 |
|
Net income | — |
| | 19 |
| | — |
| | 19 |
| — |
| | 19 |
| | — |
| | 19 |
|
Original issue shares, net | 3 |
| | — |
| | — |
| | 3 |
| 3 |
| | — |
| | — |
| | 3 |
|
Net activity related to stock-based awards | 3 |
| | — |
| | — |
| | 3 |
| 3 |
| | — |
| | — |
| | 3 |
|
Other comprehensive income, net of income taxes | — |
| | — |
| | 1 |
| | 1 |
| — |
| | — |
| | 1 |
| | 1 |
|
Balance, March 23, 2016 | $ | 3,838 |
|
| $ | 636 |
|
| $ | (35 | ) |
| $ | 4,439 |
| $ | 3,838 |
|
| $ | 636 |
|
| $ | (35 | ) |
| $ | 4,439 |
|
| | | | | | | | | | | | | | |
Successor | Membership Interest | | Undistributed Losses | | Accumulated Other Comprehensive Loss, net | | Total Member's Equity | Membership Interest | | Undistributed Gains/(Losses) | | Accumulated Other Comprehensive Loss, net | | Total Member's Equity |
Balance, March 24, 2016(b) | $ | 7,200 |
| | $ | — |
| | $ | — |
| | $ | 7,200 |
| $ | 7,200 |
| | $ | — |
| | $ | — |
| | $ | 7,200 |
|
Net loss | — |
| | (61 | ) | | — |
| | (61 | ) | — |
| | (61 | ) | | — |
| | (61 | ) |
Distribution to member(c) | (400 | ) | | — |
| | — |
| | (400 | ) | |
Contribution from member | 1,251 |
| | — |
| | — |
| | 1,251 |
| |
Distributions to member(c) | | (400 | ) | | — |
| | — |
| | (400 | ) |
Contributions from member | | 1,251 |
| | — |
| | — |
| | 1,251 |
|
Measurement period adjustment of Exelon’s deferred tax liabilities to reflect unitary state income tax consequences of the merger | 35 |
| | — |
| | — |
| | 35 |
| 35 |
| | — |
| | — |
| | 35 |
|
Distribution of net retirement benefit obligation to member | 53 |
| | — |
| | — |
| | 53 |
| 53 |
| | — |
| | — |
| | 53 |
|
Assumption of member liabilities(d) | (62 | ) | | — |
| | — |
| | (62 | ) | (62 | ) | | — |
| | — |
| | (62 | ) |
Balance, December 31, 2016 | $ | 8,077 |
|
| $ | (61 | ) |
| $ | — |
|
| $ | 8,016 |
| $ | 8,077 |
|
| $ | (61 | ) |
| $ | — |
|
| $ | 8,016 |
|
Net Income | — |
| | 362 |
| | — |
| | 362 |
| — |
| | 362 |
| | — |
| | 362 |
|
Distribution to member | — |
| | (311 | ) | | — |
| | (311 | ) | |
Contribution from member | 751 |
| | — |
| | — |
| | 751 |
| |
Allocation of tax benefit from member | 7 |
| | — |
| | — |
| | 7 |
| |
Distributions to member | | — |
| | (311 | ) | | — |
| | (311 | ) |
Contributions from member | | 758 |
| | — |
| | — |
| | 758 |
|
Balance, December 31, 2017 | $ | 8,835 |
|
| $ | (10 | ) |
| $ | — |
|
| $ | 8,825 |
| $ | 8,835 |
|
| $ | (10 | ) |
| $ | — |
|
| $ | 8,825 |
|
Net Income | | — |
| | 398 |
| | — |
| | 398 |
|
Distributions to member | | — |
| | (326 | ) | | — |
| | (326 | ) |
Contributions from member | | 385 |
| | — |
| | — |
| | 385 |
|
Balance, December 31, 2018 | | $ | 9,220 |
|
| $ | 62 |
|
| $ | — |
|
| $ | 9,282 |
|
__________
| |
(a) | At March 23, 2016 and December 31, 2015, PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively. |
| |
(b) | The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger. |
| |
(c) | Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon. |
| |
(d) | The liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 45 — Mergers, Acquisitions and Dispositions. |
See the Combined Notes to Consolidated Financial Statements
296241
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 2,152 |
| | $ | 2,181 |
| | $ | 2,124 |
| $ | 2,233 |
| | $ | 2,126 |
| | $ | 2,167 |
|
Revenues from alternative revenue programs | | — |
| | 26 |
| | 14 |
|
Operating revenues from affiliates | 6 |
| | 5 |
| | 5 |
| 6 |
| | 6 |
| | 5 |
|
Total operating revenues | 2,158 |
| | 2,186 |
| | 2,129 |
| 2,239 |
| | 2,158 |
| | 2,186 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 359 |
| | 411 |
| | 719 |
| 448 |
| | 359 |
| | 411 |
|
Purchased power from affiliates | 255 |
| | 295 |
| | — |
| 206 |
| | 255 |
| | 295 |
|
Operating and maintenance | 396 |
| | 607 |
| | 435 |
| 275 |
| | 396 |
| | 607 |
|
Operating and maintenance from affiliates | 58 |
| | 35 |
| | 4 |
| 226 |
| | 58 |
| | 35 |
|
Depreciation and amortization | 321 |
| | 295 |
| | 256 |
| 385 |
| | 321 |
| | 295 |
|
Taxes other than income | 371 |
| | 377 |
| | 376 |
| 379 |
| | 371 |
| | 377 |
|
Total operating expenses | 1,760 |
| | 2,020 |
| | 1,790 |
| 1,919 |
| | 1,760 |
| | 2,020 |
|
Gain on sales of assets | 1 |
| | 8 |
| | 46 |
| — |
| | 1 |
| | 8 |
|
Operating income | 399 |
| | 174 |
| | 385 |
| 320 |
| | 399 |
| | 174 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (121 | ) | | (127 | ) | | (124 | ) | (128 | ) | | (121 | ) | | (127 | ) |
Other, net | 32 |
| | 36 |
| | 28 |
| 31 |
| | 32 |
| | 36 |
|
Total other income and (deductions) | (89 | ) | | (91 | ) | | (96 | ) | (97 | ) | | (89 | ) | | (91 | ) |
Income before income taxes | 310 |
| | 83 |
| | 289 |
| 223 |
| | 310 |
| | 83 |
|
Income taxes | 105 |
| | 41 |
| | 102 |
| 13 |
| | 105 |
| | 41 |
|
Net income | $ | 205 |
| | $ | 42 |
| | $ | 187 |
| $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
Comprehensive income | $ | 205 |
| | $ | 42 |
| | $ | 187 |
| $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
See the Combined Notes to Consolidated Financial Statements
297242
Potomac Electric Power Company
Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income | $ | 205 |
| | $ | 42 |
| | $ | 187 |
| $ | 210 |
| | $ | 205 |
| | $ | 42 |
|
Adjustments to reconcile net income to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation and amortization | 321 |
| | 295 |
| | 256 |
| 385 |
| | 321 |
| | 295 |
|
Impairment losses on regulatory assets | 14 |
| | — |
| | — |
| — |
| | 14 |
| | — |
|
Gain on sales of assets
| (1 | ) | | (8 | ) | | (46 | ) | |
Deferred income taxes and amortization of investment tax credits | 113 |
| | 153 |
| | 150 |
| (18 | ) | | 113 |
| | 153 |
|
Other non-cash operating activities | (5 | ) | | 183 |
| | 54 |
| 60 |
| | (6 | ) | | 175 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (20 | ) | | (41 | ) | | (43 | ) | (5 | ) | | (20 | ) | | (41 | ) |
Receivables from and payables to affiliates, net | — |
| | 44 |
| | — |
| (17 | ) | | — |
| | 44 |
|
Inventories | (24 | ) | | 1 |
| | (5 | ) | (6 | ) | | (24 | ) | | 1 |
|
Accounts payable and accrued expenses | (63 | ) | | 32 |
| | (21 | ) | 59 |
| | (63 | ) | | 32 |
|
Income taxes | 81 |
| | 110 |
| | (46 | ) | (13 | ) | | 81 |
| | 110 |
|
Pension and non-pension postretirement benefit contributions | (72 | ) | | (32 | ) | | (14 | ) | (17 | ) | | (72 | ) | | (32 | ) |
Other assets and liabilities | (142 | ) | | (128 | ) | | (99 | ) | (164 | ) | | (142 | ) | | (128 | ) |
Net cash flows provided by operating activities | 407 |
| | 651 |
| | 373 |
| 474 |
| | 407 |
| | 651 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (628 | ) | | (586 | ) | | (544 | ) | (656 | ) | | (628 | ) | | (586 | ) |
Proceeds from sale of long-lived assets | 1 |
| | 12 |
| | 54 |
| |
Purchases of investments | — |
| | (30 | ) | | — |
| — |
| | — |
| | (30 | ) |
Changes in restricted cash | (2 | ) | | (31 | ) | | 3 |
| |
Other investing activities | (1 | ) | | (12 | ) | | 10 |
| 2 |
| | — |
| | — |
|
Net cash flows used in investing activities | (630 | ) | | (647 | ) | | (477 | ) | (654 | ) | | (628 | ) | | (616 | ) |
Cash flows from financing activities | | | | | | | | | | |
Changes in short-term borrowings | 3 |
| | (41 | ) | | (40 | ) | 14 |
| | 3 |
| | (41 | ) |
Issuance of long-term debt | 202 |
| | 4 |
| | 208 |
| 200 |
| | 202 |
| | 4 |
|
Retirement of long-term debt | (13 | ) | | (11 | ) | | (22 | ) | (14 | ) | | (13 | ) | | (11 | ) |
Dividends paid on common stock | (133 | ) | | (136 | ) | | (146 | ) | (169 | ) | | (133 | ) | | (136 | ) |
Contributions from parent | 161 |
| | 187 |
| | 112 |
| 166 |
| | 161 |
| | 187 |
|
Other financing activities | (1 | ) | | (3 | ) | | (9 | ) | (4 | ) | | (1 | ) | | (3 | ) |
Net cash flows provided by financing activities | 219 |
| | — |
| | 103 |
| 193 |
| | 219 |
| | — |
|
(Decrease) Increase in cash and cash equivalents | (4 | ) | | 4 |
| | (1 | ) | |
Cash and cash equivalents at beginning of period | 9 |
| | 5 |
| | 6 |
| |
Cash and cash equivalents at end of period | $ | 5 |
| | $ | 9 |
| | $ | 5 |
| |
Increase (decrease) in cash, cash equivalents and restricted cash | | 13 |
| | (2 | ) | | 35 |
|
Cash, cash equivalents and restricted cash at beginning of period | | 40 |
| | 42 |
| | 7 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 53 |
| | $ | 40 |
| | $ | 42 |
|
See the Combined Notes to Consolidated Financial Statements
298243
Potomac Electric Power Company
Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 5 |
| | $ | 9 |
| $ | 16 |
| | $ | 5 |
|
Restricted cash and cash equivalents | 35 |
| | 33 |
| 37 |
| | 35 |
|
Accounts receivable, net | | | | | | |
Customer | 250 |
| | 235 |
| 225 |
| | 250 |
|
Other | 87 |
| | 150 |
| 81 |
| | 87 |
|
Receivables from affiliates | | 1 |
| | — |
|
Inventories, net | 87 |
| | 63 |
| 93 |
| | 87 |
|
Regulatory assets | 213 |
| | 162 |
| 270 |
| | 213 |
|
Other | 33 |
| | 32 |
| 37 |
| | 33 |
|
Total current assets | 710 |
| | 684 |
| 760 |
| | 710 |
|
Property, plant and equipment, net | 6,001 |
| | 5,571 |
| 6,460 |
| | 6,001 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 678 |
| | 690 |
| 643 |
| | 678 |
|
Investments | 102 |
| | 102 |
| 105 |
| | 102 |
|
Prepaid pension asset | 322 |
| | 282 |
| 316 |
| | 322 |
|
Other | 19 |
| | 6 |
| 15 |
| | 19 |
|
Total deferred debits and other assets | 1,121 |
|
| 1,080 |
| 1,079 |
|
| 1,121 |
|
Total assets | $ | 7,832 |
| | $ | 7,335 |
| $ | 8,299 |
| | $ | 7,832 |
|
See the Combined Notes to Consolidated Financial Statements
299244
Potomac Electric Power Company
Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 26 |
| | $ | 23 |
| $ | 40 |
| | $ | 26 |
|
Long-term debt due within one year | 19 |
| | 16 |
| 15 |
| | 19 |
|
Accounts payable | 139 |
| | 209 |
| 214 |
| | 139 |
|
Accrued expenses | 137 |
| | 113 |
| 126 |
| | 137 |
|
Payables to affiliates | 74 |
| | 74 |
| 62 |
| | 74 |
|
Regulatory liabilities | | 7 |
| | 3 |
|
Customer deposits | 54 |
| | 53 |
| 54 |
| | 54 |
|
Regulatory liabilities | 3 |
| | 11 |
| |
Merger related obligation | 42 |
| | 68 |
| 38 |
| | 42 |
|
Current portion of DC PLUG obligation | 28 |
| | — |
| 30 |
| | 28 |
|
Other | 28 |
| | 29 |
| 42 |
| | 28 |
|
Total current liabilities | 550 |
| — |
| 596 |
| 628 |
| — |
| 550 |
|
Long-term debt | 2,521 |
| | 2,333 |
| 2,704 |
| | 2,521 |
|
Deferred credits and other liabilities | | | | | | |
Regulatory liabilities | 829 |
| | 20 |
| |
Deferred income taxes and unamortized investment tax credits | 1,063 |
| | 1,910 |
| 1,064 |
| | 1,063 |
|
Non-pension postretirement benefit obligations | 36 |
| | 43 |
| 29 |
| | 36 |
|
Regulatory liabilities | | 822 |
| | 829 |
|
Other | 300 |
| | 133 |
| 312 |
| | 300 |
|
Total deferred credits and other liabilities | 2,228 |
| | 2,106 |
| 2,227 |
| | 2,228 |
|
Total liabilities | 5,299 |
| | 5,035 |
| 5,559 |
| | 5,299 |
|
Commitments and contingencies | | | |
| |
|
Shareholder's equity | | | | | | |
Common stock | 1,470 |
| | 1,309 |
| 1,636 |
| | 1,470 |
|
Retained earnings | 1,063 |
| | 991 |
| 1,104 |
| | 1,063 |
|
Total shareholder's equity | 2,533 |
| | 2,300 |
| 2,740 |
| | 2,533 |
|
Total liabilities and shareholder's equity | $ | 7,832 |
|
| $ | 7,335 |
| $ | 8,299 |
|
| $ | 7,832 |
|
See the Combined Notes to Consolidated Financial Statements
300245
Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
| | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
Balance, December 31, 2014 | $ | 1,010 |
| | $ | 1,077 |
| | $ | 2,087 |
| |
Net income | — |
| | 187 |
| | 187 |
| |
Common stock dividends | — |
| | (146 | ) | | (146 | ) | |
Contribution from Parent | 112 |
| | — |
| | 112 |
| |
Balance, December 31, 2015 | $ | 1,122 |
| | $ | 1,118 |
| | $ | 2,240 |
| $ | 1,122 |
| | $ | 1,118 |
| | $ | 2,240 |
|
Net income
| — |
| | 42 |
| | 42 |
| — |
| | 42 |
| | 42 |
|
Common stock dividends | — |
| | (169 | ) | | (169 | ) | — |
| | (169 | ) | | (169 | ) |
Contribution from Parent | 187 |
| | — |
| | 187 |
| |
Contributions from parent | | 187 |
| | — |
| | 187 |
|
Balance, December 31, 2016 | $ | 1,309 |
| | $ | 991 |
| | $ | 2,300 |
| $ | 1,309 |
| | $ | 991 |
| | $ | 2,300 |
|
Net income
| — |
| | 205 |
| | 205 |
| — |
| | 205 |
| | 205 |
|
Common stock dividends | — |
| | (133 | ) | | (133 | ) | — |
| | (133 | ) | | (133 | ) |
Contribution from Parent | 161 |
| | — |
| | 161 |
| |
Contributions from parent | | 161 |
| | — |
| | 161 |
|
Balance, December 31, 2017 | $ | 1,470 |
| | $ | 1,063 |
| | $ | 2,533 |
| $ | 1,470 |
| | $ | 1,063 |
| | $ | 2,533 |
|
Net income | | — |
| | 210 |
| | 210 |
|
Common stock dividends | | — |
| | (169 | ) | | (169 | ) |
Contributions from parent | | 166 |
| | — |
| | 166 |
|
Balance, December 31, 2018 | | $ | 1,636 |
| | $ | 1,104 |
| | $ | 2,740 |
|
See the Combined Notes to Consolidated Financial Statements
301246
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income (Loss)
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 1,131 |
| | $ | 1,122 |
| | $ | 1,132 |
| $ | 1,139 |
| | $ | 1,125 |
| | $ | 1,128 |
|
Natural gas operating revenues | 161 |
| | 148 |
| | 164 |
| 181 |
| | 161 |
| | 148 |
|
Revenues from alternative revenue programs | | 4 |
| | 6 |
| | (6 | ) |
Operating revenues from affiliates | 8 |
| | 7 |
| | 6 |
| 8 |
| | 8 |
| | 7 |
|
Total operating revenues | 1,300 |
|
| 1,277 |
|
| 1,302 |
| 1,332 |
|
| 1,300 |
|
| 1,277 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 282 |
| | 369 |
| | 555 |
| 352 |
| | 282 |
| | 369 |
|
Purchased fuel | 71 |
| | 60 |
| | 79 |
| 89 |
| | 71 |
| | 60 |
|
Purchased power from affiliate | 179 |
| | 154 |
| | — |
| |
Purchased power from affiliates | | 120 |
| | 179 |
| | 154 |
|
Operating and maintenance | 283 |
| | 422 |
| | 303 |
| 182 |
| | 283 |
| | 422 |
|
Operating and maintenance from affiliates | 32 |
| | 19 |
| | 1 |
| 162 |
| | 32 |
| | 19 |
|
Depreciation and amortization | 167 |
| | 157 |
| | 148 |
| 182 |
| | 167 |
| | 157 |
|
Taxes other than income | 57 |
| | 55 |
| | 51 |
| 56 |
| | 57 |
| | 55 |
|
Total operating expenses | 1,071 |
|
| 1,236 |
|
| 1,137 |
| 1,143 |
|
| 1,071 |
|
| 1,236 |
|
Gain on sales of assets | — |
| | 9 |
| | — |
| 1 |
| | — |
| | 9 |
|
Operating income | 229 |
|
| 50 |
|
| 165 |
| 190 |
|
| 229 |
|
| 50 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (51 | ) | | (50 | ) | | (50 | ) | (58 | ) | | (51 | ) | | (50 | ) |
Other, net | 14 |
| | 13 |
| | 10 |
| 10 |
| | 14 |
| | 13 |
|
Total other income and (deductions) | (37 | ) |
| (37 | ) |
| (40 | ) | (48 | ) |
| (37 | ) |
| (37 | ) |
Income before income taxes | 192 |
|
| 13 |
|
| 125 |
| 142 |
|
| 192 |
|
| 13 |
|
Income taxes | 71 |
| | 22 |
| | 49 |
| 22 |
| | 71 |
| | 22 |
|
Net income (loss) | $ | 121 |
|
| $ | (9 | ) |
| $ | 76 |
| $ | 120 |
|
| $ | 121 |
|
| $ | (9 | ) |
Comprehensive income (loss) | $ | 121 |
|
| $ | (9 | ) |
| $ | 76 |
| $ | 120 |
|
| $ | 121 |
|
| $ | (9 | ) |
See the Combined Notes to Consolidated Financial Statements
302247
Delmarva Power & Light Company
Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income (loss) | $ | 121 |
| | $ | (9 | ) | | $ | 76 |
| $ | 120 |
| | $ | 121 |
| | $ | (9 | ) |
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities: | | | | | | | | | | |
Depreciation and amortization | 167 |
| | 157 |
| | 148 |
| 182 |
| | 167 |
| | 157 |
|
Impairment losses on regulatory assets | 6 |
| | — |
| | — |
| — |
| | 6 |
| | — |
|
Deferred income taxes and amortization of investment tax credits | 89 |
| | 109 |
| | 73 |
| 24 |
| | 89 |
| | 109 |
|
Other non-cash operating activities | 9 |
| | 114 |
| | 33 |
| 24 |
| | 9 |
| | 114 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | (22 | ) | | (5 | ) | | (24 | ) | 8 |
| | (22 | ) | | (5 | ) |
Receivables from and payables to affiliates, net | 11 |
| | 13 |
| | 3 |
| (9 | ) | | 11 |
| | 13 |
|
Inventories | (5 | ) | | — |
| | 6 |
| (3 | ) | | (5 | ) | | — |
|
Accounts payable and accrued expenses | (8 | ) | | (4 | ) | | (8 | ) | 11 |
| | (8 | ) | | (4 | ) |
Collateral (posted) received, net | — |
| | 1 |
| | (1 | ) | |
Collateral received, net | | — |
| | — |
| | 1 |
|
Income taxes | 26 |
| | 28 |
| | (26 | ) | 2 |
| | 26 |
| | 28 |
|
Pension and non-pension postretirement benefit contributions | (2 | ) | | (22 | ) | | — |
| — |
| | (2 | ) | | (22 | ) |
Other assets and liabilities | (71 | ) | | (72 | ) | | (14 | ) | (7 | ) | | (71 | ) | | (72 | ) |
Net cash flows provided by operating activities | 321 |
|
| 310 |
|
| 266 |
| 352 |
|
| 321 |
|
| 310 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (428 | ) | | (349 | ) | | (352 | ) | (364 | ) | | (428 | ) | | (349 | ) |
Proceeds from sales of long-lived assets | — |
| | 9 |
| | — |
| |
Change in restricted cash | — |
| | — |
| | 5 |
| |
Other investing activities | (1 | ) | | 4 |
| | 2 |
| 2 |
| | (1 | ) | | 13 |
|
Net cash flows used in investing activities | (429 | ) |
| (336 | ) |
| (345 | ) | (362 | ) |
| (429 | ) |
| (336 | ) |
Cash flows from financing activities | | | | | | | | | | |
Change in short-term borrowings | 216 |
| | (105 | ) | | (1 | ) | (216 | ) | | 216 |
| | (105 | ) |
Issuance of long-term debt | — |
| | 175 |
| | 200 |
| 200 |
| | — |
| | 175 |
|
Retirement of long-term debt | (40 | ) | | (100 | ) | | (100 | ) | (4 | ) | | (40 | ) | | (100 | ) |
Dividends paid on common stock | (112 | ) | | (54 | ) | | (92 | ) | (96 | ) | | (112 | ) | | (54 | ) |
Contributions from parent | — |
| | 152 |
| | 75 |
| 150 |
| | — |
| | 152 |
|
Other financing activities | — |
| | (1 | ) | | (2 | ) | (2 | ) | | — |
| | (1 | ) |
Net cash flows provided by financing activities | 64 |
|
| 67 |
|
| 80 |
| 32 |
|
| 64 |
|
| 67 |
|
(Decrease) Increase in cash and cash equivalents | (44 | ) | | 41 |
| | 1 |
| |
Cash and cash equivalents at beginning of period | 46 |
| | 5 |
| | 4 |
| |
Cash and cash equivalents at end of period | $ | 2 |
|
| $ | 46 |
|
| $ | 5 |
| |
Increase (decrease) in cash, cash equivalents and restricted cash | | 22 |
| | (44 | ) | | 41 |
|
Cash, cash equivalents and restricted cash at beginning of period | | 2 |
| | 46 |
| | 5 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 24 |
|
| $ | 2 |
|
| $ | 46 |
|
See the Combined Notes to Consolidated Financial Statements
303248
Delmarva Power & Light Company
Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 2 |
| | $ | 46 |
| $ | 23 |
| | $ | 2 |
|
Restricted cash and cash equivalents | | 1 |
| | — |
|
Accounts receivable, net | | | | | | |
Customer | 146 |
| | 136 |
| 134 |
| | 146 |
|
Other | 38 |
| | 63 |
| 46 |
| | 38 |
|
Receivables from affiliates | — |
| | 3 |
| |
Inventories, net | | | | | | |
Gas held in storage | 7 |
| | 7 |
| 9 |
| | 7 |
|
Materials and supplies | 36 |
| | 32 |
| 37 |
| | 36 |
|
Regulatory assets | 69 |
| | 59 |
| 59 |
| | 69 |
|
Other | 27 |
| | 24 |
| 27 |
| | 27 |
|
Total current assets | 325 |
|
| 370 |
| 336 |
|
| 325 |
|
Property, plant and equipment, net | 3,579 |
| | 3,273 |
| 3,821 |
| | 3,579 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 245 |
| | 289 |
| 231 |
| | 245 |
|
Goodwill | 8 |
| | 8 |
| 8 |
| | 8 |
|
Prepaid pension asset | 193 |
| | 206 |
| 186 |
| | 193 |
|
Other | 7 |
| | 7 |
| 6 |
| | 7 |
|
Total deferred debits and other assets | 453 |
|
| 510 |
| 431 |
|
| 453 |
|
Total assets | $ | 4,357 |
|
| $ | 4,153 |
| $ | 4,588 |
|
| $ | 4,357 |
|
See the Combined Notes to Consolidated Financial Statements
304249
Delmarva Power & Light Company
Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 216 |
| | $ | — |
| $ | — |
| | $ | 216 |
|
Long-term debt due within one year | 83 |
| | 119 |
| 91 |
| | 83 |
|
Accounts payable | 82 |
| | 88 |
| 111 |
| | 82 |
|
Accrued expenses | 35 |
| | 36 |
| 39 |
| | 35 |
|
Payables to affiliates | 46 |
| | 38 |
| 33 |
| | 46 |
|
Regulatory liabilities | | 59 |
| | 42 |
|
Customer deposits | 35 |
| | 36 |
| 35 |
| | 35 |
|
Regulatory liabilities | 42 |
| | 43 |
| |
Merger related obligation | — |
| | 13 |
| |
Other | 8 |
| | 8 |
| 7 |
| | 8 |
|
Total current liabilities | 547 |
|
| 381 |
| 375 |
|
| 547 |
|
Long-term debt | 1,217 |
| | 1,221 |
| 1,403 |
| | 1,217 |
|
Deferred credits and other liabilities | | | | | | |
Regulatory liabilities | 593 |
| | 97 |
| |
Deferred income taxes and unamortized investment tax credits | 603 |
| | 1,056 |
| 628 |
| | 603 |
|
Non-pension postretirement benefit obligations | 14 |
| | 19 |
| 17 |
| | 14 |
|
Regulatory liabilities | | 606 |
| | 593 |
|
Other | 48 |
| | 53 |
| 50 |
| | 48 |
|
Total deferred credits and other liabilities | 1,258 |
|
| 1,225 |
| 1,301 |
|
| 1,258 |
|
Total liabilities | 3,022 |
|
| 2,827 |
| 3,079 |
|
| 3,022 |
|
Commitments and contingencies | | | |
|
| |
|
|
Shareholder's equity | | | | | | |
Common stock | 764 |
| | 764 |
| 914 |
| | 764 |
|
Retained earnings | 571 |
| | 562 |
| 595 |
| | 571 |
|
Total shareholder's equity | 1,335 |
|
| 1,326 |
| 1,509 |
|
| 1,335 |
|
Total liabilities and shareholder's equity | $ | 4,357 |
|
| $ | 4,153 |
| $ | 4,588 |
|
| $ | 4,357 |
|
See the Combined Notes to Consolidated Financial Statements
305250
Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
| | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
Balance, December 31, 2014 | $ | 537 |
| | $ | 641 |
| | $ | 1,178 |
| |
Net income | — |
| | 76 |
| | 76 |
| |
Common stock dividends | — |
| | (92 | ) | | (92 | ) | |
Contribution from parent | 75 |
| | — |
| | 75 |
| |
Balance, December 31, 2015 | $ | 612 |
| | $ | 625 |
|
| $ | 1,237 |
| $ | 612 |
| | $ | 625 |
| | $ | 1,237 |
|
Net loss | — |
| | (9 | ) | | (9 | ) | — |
| | (9 | ) | | (9 | ) |
Common stock dividends | — |
| | (54 | ) | | (54 | ) | — |
| | (54 | ) | | (54 | ) |
Contribution from parent | 152 |
| | — |
| | 152 |
| |
Contributions from parent | | 152 |
| | — |
| | 152 |
|
Balance, December 31, 2016 | $ | 764 |
| | $ | 562 |
|
| $ | 1,326 |
| $ | 764 |
| | $ | 562 |
|
| $ | 1,326 |
|
Net income | — |
| | 121 |
| | 121 |
| — |
| | 121 |
| | 121 |
|
Common stock dividends | — |
| | (112 | ) | | (112 | ) | — |
| | (112 | ) | | (112 | ) |
Balance, December 31, 2017 | $ | 764 |
| | $ | 571 |
|
| $ | 1,335 |
| $ | 764 |
| | $ | 571 |
|
| $ | 1,335 |
|
Net income | | — |
| | 120 |
| | 120 |
|
Common stock dividends | | — |
| | (96 | ) | | (96 | ) |
Contributions from parent | | 150 |
| | — |
| | 150 |
|
Balance, December 31, 2018 | | $ | 914 |
| | $ | 595 |
|
| $ | 1,509 |
|
See the Combined Notes to Consolidated Financial Statements
306251
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income (Loss)
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues | | | | | | | | | | |
Electric operating revenues | $ | 1,184 |
| | $ | 1,254 |
| | $ | 1,291 |
| $ | 1,237 |
| | $ | 1,176 |
| | $ | 1,245 |
|
Revenues from alternative revenue programs | | (4 | ) | | 8 |
| | 9 |
|
Operating revenues from affiliates | 2 |
| | 3 |
| | 4 |
| 3 |
| | 2 |
| | 3 |
|
Total operating revenues | 1,186 |
|
| 1,257 |
|
| 1,295 |
| 1,236 |
|
| 1,186 |
|
| 1,257 |
|
Operating expenses | | | | | | | | | | |
Purchased power | 541 |
| | 614 |
| | 708 |
| 587 |
| | 541 |
| | 614 |
|
Purchased power from affiliates | 29 |
| | 37 |
| | — |
| 29 |
| | 29 |
| | 37 |
|
Operating and maintenance | 279 |
| | 410 |
| | 268 |
| 188 |
| | 279 |
| | 410 |
|
Operating and maintenance from affiliates | 28 |
| | 18 |
| | 3 |
| 142 |
| | 28 |
| | 18 |
|
Depreciation and amortization | 146 |
| | 165 |
| | 175 |
| 136 |
| | 146 |
| | 165 |
|
Taxes other than income | 6 |
| | 7 |
| | 7 |
| 5 |
| | 6 |
| | 7 |
|
Total operating expenses | 1,029 |
|
| 1,251 |
|
| 1,161 |
| 1,087 |
|
| 1,029 |
|
| 1,251 |
|
Gain on sale of assets | — |
| | 1 |
| | — |
| — |
| | — |
| | 1 |
|
Operating income | 157 |
|
| 7 |
|
| 134 |
| 149 |
|
| 157 |
|
| 7 |
|
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (61 | ) | | (62 | ) | | (64 | ) | (64 | ) | | (61 | ) | | (62 | ) |
Other, net | 7 |
| | 9 |
| | 3 |
| 2 |
| | 7 |
| | 9 |
|
Total other income and (deductions) | (54 | ) |
| (53 | ) |
| (61 | ) | (62 | ) |
| (54 | ) |
| (53 | ) |
Income (loss) before income taxes | 103 |
|
| (46 | ) |
| 73 |
| 87 |
|
| 103 |
|
| (46 | ) |
Income taxes | 26 |
| | (4 | ) | | 33 |
| 12 |
| | 26 |
| | (4 | ) |
Net income (loss) | $ | 77 |
|
| $ | (42 | ) |
| $ | 40 |
| $ | 75 |
|
| $ | 77 |
|
| $ | (42 | ) |
Comprehensive income (loss) | $ | 77 |
|
| $ | (42 | ) |
| $ | 40 |
| $ | 75 |
|
| $ | 77 |
|
| $ | (42 | ) |
See the Combined Notes to Consolidated Financial Statements
307252
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Cash flows from operating activities | | | | | | | | | | |
Net income (loss) | $ | 77 |
| | $ | (42 | ) | | $ | 40 |
| $ | 75 |
| | $ | 77 |
| | $ | (42 | ) |
Adjustments to reconcile net income (loss) to net cash from operating activities: | | | | | | | | | | |
Depreciation and amortization | 146 |
| | 165 |
| | 175 |
| 136 |
| | 146 |
| | 165 |
|
Impairment losses on regulatory assets | 7 |
| | — |
| | — |
| — |
| | 7 |
| | — |
|
Deferred income taxes and amortization of investment tax credits | 32 |
| | 22 |
| | 31 |
| 25 |
| | 32 |
| | 22 |
|
Other non-cash operating activities | 17 |
| | 155 |
| | 37 |
| 24 |
| | 17 |
| | 155 |
|
Changes in assets and liabilities: | | | | | | | | | | |
Accounts receivable | 14 |
| | (8 | ) | | (67 | ) | (8 | ) | | 14 |
| | (8 | ) |
Receivables from and payables to affiliates, net | — |
| | 13 |
| | 1 |
| 1 |
| | — |
| | 13 |
|
Inventories | (7 | ) | | (1 | ) | | (1 | ) | (4 | ) | | (7 | ) | | (1 | ) |
Accounts payable and accrued expenses | (2 | ) | | 9 |
| | 9 |
| (7 | ) | | (2 | ) | | 9 |
|
Income taxes | (11 | ) | | 174 |
| | (34 | ) | (2 | ) | | (11 | ) | | 174 |
|
Pension and non-pension postretirement benefit contributions | (20 | ) | | (17 | ) | | (2 | ) | (6 | ) | | (20 | ) | | (17 | ) |
Other assets and liabilities | (47 | ) | | (85 | ) | | 67 |
| (6 | ) | | (47 | ) | | (85 | ) |
Net cash flows provided by operating activities | 206 |
|
| 385 |
|
| 256 |
| 228 |
|
| 206 |
|
| 385 |
|
Cash flows from investing activities | | | | | | | | | | |
Capital expenditures | (312 | ) | | (311 | ) | | (300 | ) | (335 | ) | | (312 | ) | | (311 | ) |
Proceeds from sale of long-lived assets | — |
| | 2 |
| | — |
| |
Changes in restricted cash | 3 |
| | (2 | ) | | (6 | ) | |
Other investing activities | (1 | ) | | 2 |
| | — |
| 1 |
| | (1 | ) | | 4 |
|
Net cash flows used in investing activities | (310 | ) |
| (309 | ) |
| (306 | ) | (334 | ) |
| (313 | ) |
| (307 | ) |
Cash flows from financing activities | | | | | | | | | | |
Change in short-term borrowings | 108 |
| | (5 | ) | | (122 | ) | (94 | ) | | 108 |
| | (5 | ) |
Proceeds from short-term borrowings with maturities greater than 90 days | | 125 |
| | — |
| | — |
|
Issuance of long-term debt | — |
| | — |
| | 150 |
| 350 |
| | — |
| | — |
|
Retirement of long-term debt | (35 | ) | | (48 | ) | | (58 | ) | (281 | ) | | (35 | ) | | (48 | ) |
Dividends paid on common stock | (68 | ) | | (63 | ) | | (12 | ) | (59 | ) | | (68 | ) | | (63 | ) |
Contributions from parent | — |
| | 139 |
| | 95 |
| 67 |
| | — |
| | 139 |
|
Other financing activities | — |
| | (1 | ) | | (2 | ) | (3 | ) | | — |
| | (1 | ) |
Net cash flows provided by financing activities | 5 |
|
| 22 |
|
| 51 |
| 105 |
|
| 5 |
|
| 22 |
|
(Decrease) Increase in cash and cash equivalents | (99 | ) |
| 98 |
|
| 1 |
| |
Cash and cash equivalents at beginning of period | 101 |
| | 3 |
| | 2 |
| |
Cash and cash equivalents at end of period | $ | 2 |
|
| $ | 101 |
|
| $ | 3 |
| |
(Decrease) increase in cash, cash equivalents and restricted cash | | (1 | ) |
| (102 | ) |
| 100 |
|
Cash, cash equivalents and restricted cash at beginning of period | | 31 |
| | 133 |
| | 33 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 30 |
|
| $ | 31 |
|
| $ | 133 |
|
See the Combined Notes to Consolidated Financial Statements
308253
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 2 |
| | $ | 101 |
| $ | 7 |
| | $ | 2 |
|
Restricted cash and cash equivalents | 6 |
| | 9 |
| 4 |
| | 6 |
|
Accounts receivable, net | | | | | | |
Customer | 92 |
| | 125 |
| 95 |
| | 92 |
|
Other | 56 |
| | 44 |
| 55 |
| | 56 |
|
Receivables from affiliates | | 1 |
| | — |
|
Inventories, net | 29 |
| | 22 |
| 33 |
| | 29 |
|
Regulatory assets | 71 |
| | 96 |
| 40 |
| | 71 |
|
Other | 2 |
| | 2 |
| 5 |
| | 2 |
|
Total current assets | 258 |
|
| 399 |
| 240 |
|
| 258 |
|
Property, plant and equipment, net | 2,706 |
| | 2,521 |
| 2,966 |
| | 2,706 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 359 |
| | 405 |
| 386 |
| | 359 |
|
Long-term note receivable | 4 |
| | 4 |
| — |
| | 4 |
|
Prepaid pension asset | 73 |
| | 84 |
| 67 |
| | 73 |
|
Other | 45 |
| | 44 |
| 40 |
| | 45 |
|
Total deferred debits and other assets | 481 |
|
| 537 |
| 493 |
|
| 481 |
|
Total assets(a) | $ | 3,445 |
|
| $ | 3,457 |
| $ | 3,699 |
|
| $ | 3,445 |
|
See the Combined Notes to Consolidated Financial Statements
309254
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDER'S EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 108 |
| | $ | — |
| $ | 139 |
| | $ | 108 |
|
Long-term debt due within one year | 281 |
| | 35 |
| 18 |
| | 281 |
|
Accounts payable | 118 |
| | 132 |
| 154 |
| | 118 |
|
Accrued expenses | 33 |
| | 38 |
| 35 |
| | 33 |
|
Payables to affiliates | 29 |
| | 29 |
| 28 |
| | 29 |
|
Regulatory liabilities | | 18 |
| | 11 |
|
Customer deposits | 31 |
| | 33 |
| 26 |
| | 31 |
|
Regulatory liabilities | 11 |
| | 25 |
| |
Merger related obligation | — |
| | 20 |
| |
Other | 8 |
| | 8 |
| 4 |
| | 8 |
|
Total current liabilities | 619 |
|
| 320 |
| 422 |
|
| 619 |
|
Long-term debt | 840 |
| | 1,120 |
| 1,170 |
| | 840 |
|
Deferred credits and other liabilities | | | | | | |
Deferred income taxes and unamortized investment tax credits | 493 |
| | 917 |
| 535 |
| | 493 |
|
Non-pension postretirement benefit obligations | 14 |
| | 34 |
| 17 |
| | 14 |
|
Regulatory liabilities | 411 |
| | — |
| 402 |
| | 411 |
|
Other | 25 |
| | 32 |
| 27 |
| | 25 |
|
Total deferred credits and other liabilities | 943 |
|
| 983 |
| 981 |
|
| 943 |
|
Total liabilities(a) | 2,402 |
|
| 2,423 |
| 2,573 |
|
| 2,402 |
|
Commitments and contingencies | | | |
| |
|
Shareholder's equity | | | | | | |
Common stock | 912 |
| | 912 |
| 979 |
| | 912 |
|
Retained earnings | 131 |
| | 122 |
| 147 |
| | 131 |
|
Total shareholder's equity | 1,043 |
|
| 1,034 |
| 1,126 |
|
| 1,043 |
|
Total liabilities and shareholder's equity | $ | 3,445 |
|
| $ | 3,457 |
| $ | 3,699 |
|
| $ | 3,445 |
|
_____________
| |
(a) | ACE’s consolidated assets include $29$23 million and $32$29 million at December 31, 20172018 and 2016,2017, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $90$59 million and $126$90 millionat December 31, 20172018 and 2016,2017, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities.Entities for additional information. |
See the Combined Notes to Consolidated Financial Statements
310255
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
| | (In millions) | Common Stock | | Retained Earnings | | Total Shareholder's Equity | Common Stock | | Retained Earnings | | Total Shareholder's Equity |
Balance, December 31, 2014 | $ | 678 |
| | $ | 199 |
| | $ | 877 |
| |
Net income | — |
| | 40 |
| | 40 |
| |
Common stock dividends | — |
| | (12 | ) | | (12 | ) | |
Contribution from parent | 95 |
| | — |
| | 95 |
| |
Balance, December 31, 2015 | $ | 773 |
|
| $ | 227 |
| | $ | 1,000 |
| $ | 773 |
| | $ | 227 |
| | $ | 1,000 |
|
Net loss | — |
| | (42 | ) | | (42 | ) | — |
| | (42 | ) | | (42 | ) |
Common stock dividends | — |
| | (63 | ) | | (63 | ) | — |
| | (63 | ) | | (63 | ) |
Contribution from parent | 139 |
| | — |
| | 139 |
| |
Contributions from parent | | 139 |
| | — |
| | 139 |
|
Balance, December 31, 2016 | $ | 912 |
|
| $ | 122 |
| | $ | 1,034 |
| $ | 912 |
|
| $ | 122 |
| | $ | 1,034 |
|
Net income | — |
| | 77 |
| | 77 |
| — |
| | 77 |
| | 77 |
|
Common stock dividends | — |
| | (68 | ) | | (68 | ) | — |
| | (68 | ) | | (68 | ) |
Balance, December 31, 2017 | $ | 912 |
|
| $ | 131 |
| | $ | 1,043 |
| $ | 912 |
|
| $ | 131 |
| | $ | 1,043 |
|
Net income | | — |
| | 75 |
| | 75 |
|
Common stock dividends | | — |
| | (59 | ) | | (59 | ) |
Contribution from parent | | 67 |
| | — |
| | 67 |
|
Balance, December 31, 2018 | | $ | 979 |
|
| $ | 147 |
| | $ | 1,126 |
|
See the Combined Notes to Consolidated Financial Statements
311256
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Index to Combined Notes to Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes apply:
Applicable Notes
| | Registrant | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | 21 | 22 | 23 | 24 | 25 | 26 | 27 | 28 | 1 | 2 | 3 | 4 | 5 | 6 | 7 | 8 | 9 | 10 | 11 | 12 | 13 | 14 | 15 | 16 | 17 | 18 | 19 | 20 | 21 | 22 | 23 | 24 | 25 | 26 | 27 |
Exelon Corporation | . | . | . | . |
Exelon Generation Company, LLC | . | | . | | . | . | | . | | . |
Commonwealth Edison Company | . | | . | | . | | . | | . | . | | . | | . | | . | |
PECO Energy Company | . | | . | | . | | . | | . | | . | | . | | . | | . | |
Baltimore Gas and Electric Company | . | | . | | . | | . | | . | | . | | . | | . | | . | | . | | . | |
Pepco Holdings LLC | . | | . | | . | | . | | . | | . | | . | | . | |
Potomac Electric Power Company | . | | . | | . | | . | | . | | . | | . | |
Delmarva Power & Light Company | . | | . | | . | | . | | . | | . | | . | |
Atlantic City Electric Company | . | | . | | . | | . | | . | | . | | . | | . | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged through its principal subsidiaries in the generation, delivery and marketing of energy generationthrough Generation and the energy distribution and transmission businesses. Prior to March 23, 2016, Exelon's principal, wholly owned subsidiaries included Generation,businesses through ComEd, PECO, BGE, Pepco, DPL and BGE.ACE. On March 23, 2016, in conjunction withExelon completed 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,merger with PHI, continuing as the surviving entity aswhich became a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions for furtheradditional information regarding the merger transaction.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | |
Name of Registrant | | Business | | Service Territories |
| | | | |
Exelon Generation Company, LLC | | Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services. | | Six reportable segments: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions |
| | | | |
Commonwealth Edison Company | | Purchase and regulated retail sale of electricity | | Northern Illinois, including the City of Chicago |
| | Transmission and distribution of electricity to retail customers | | |
| | | | |
PECO Energy Company | | Purchase and regulated retail sale of electricity and natural gas | | Southeastern Pennsylvania, including the City of Philadelphia (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Pennsylvania counties surrounding the City of Philadelphia (natural gas)
|
| | | | |
Baltimore Gas and Electric Company | | Purchase and regulated retail sale of electricity and natural gas | | Central Maryland, including the City of Baltimore (electricity and natural gas) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | |
| | | | |
Pepco Holdings LLC | | Utility services holding company engaged, through its reportable segments Pepco, DPL and ACE | | Service Territories of Pepco, DPL and ACE |
| | | | |
Potomac Electric Power Company | | Purchase and regulated retail sale of electricity | | District of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland. |
| | Transmission and distribution of electricity to retail customers | | |
| | | | |
Delmarva Power & Light Company | | Purchase and regulated retail sale of electricity and natural gas | | Portions of Delaware and Maryland (electricity) |
| | Transmission and distribution of electricity and distribution of natural gas to retail customers | | Portions of New Castle County, Delaware (natural gas) |
| | | | |
Atlantic City Electric Company | | Purchase and regulated retail sale of electricity | | Portions of Southern New Jersey |
| | Transmission and distribution of electricity to retail customers | | |
Basis of Presentation (All Registrants)
This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
As a result of the acquisition ofmerger with PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which 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. Exelonit 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 results of operations and the financial positions of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly owned subsidiary utility registrants, Pepco, DPL and ACE.
For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon now also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations, and power procurement, to PHI operating companies. The costs of BSC including support services,and PHISCO are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base.subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
PHISCO, 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 PHISCO and the participating operating subsidiaries.
Exelon owns 100% of its significant consolidated subsidiaries, includingGeneration, PECO, BGE and PHI either directly or indirectly, except for ComEd, of which Exelon ownsand more than 99%. As of December 31, 2017, Exelon owned none of BGE's preferred securities, which BGE redeemed in 2016. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2017 and December 31, 2016, as equity, in its consolidated financial statements. BGE is subject to certain ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters. PHI is subject to some ring-fencing measures established by orders of the DCPSC, DPSC, MDPSC and NJBPU, pursuant to which all of the membership interest in PHI is held directly by PH Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (PH Utility), Inc., an unrelated party, holds a nominal non-economic interest in PH Holdco LLC with limited voting rights on specified matters.ComEd. PHI owns 100% of its subsidiaries including Pepco, DPL and ACE.
Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and ExGen Renewables Partners, LLC,EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussionadditional information of Exelon’s and Generation’s consolidated VIEs.
The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which the Registrant can exercise control over the operations and policies of the investee, or the results of a model that identifies the Registrant or one of its subsidiaries as the primary beneficiary of a VIE. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or cost method accounting for investments in equity securities without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd PECO and BGE.PECO. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use cost
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollarsaccounting for investments in millions, except per share data unless otherwise noted)
method accountingequity securities without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under cost method accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost and recognize income only toadjusted for changes from observable transactions for identical or similar investments of the extent dividends or distributionssame issuer, less impairment. Changes in measurement are received.reported in earnings.
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
Use of Estimates (All Registrants)
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.
Prior Period Adjustments and Reclassifications (All Registrants)
Certain prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows, Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been reclassified between line itemsrecasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018. See New Accounting Standards below for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, cash flows from operating activities or financial positions.additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Accounting for the Effects of Regulation (Exelon ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)the Utility Registrants)
TheFor their regulated electric and gas operations, Exelon and the Utility Registrants apply the authoritative guidance for accounting for certain types of regulation, which requires them to record in their consolidated financial statementsreflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recordedExelon's regulatory assets and liabilities will beas of the balance sheet date are probable of being recovered andor settled respectively, in future rates. Exelon and the Utility Registrants continue to evaluate their respective abilities to continue to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions.statements. See Note 34 — Regulatory Matters for additional information.
With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settled to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollarsnon-current in millions, except per share data unless otherwise noted)
current onExelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.
TheExelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (All Registrants)
Operating Revenues
OperatingRevenues. The Registrants’ operating revenues are recorded as service is renderedgenerally consist of revenues from contracts with customers involving the sale and delivery of energy commodities and related products and services, utility revenues from alternative revenue programs (ARP), and realized and unrealized revenues recognized under mark-to-market energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or energy is deliveredservices to customers.customers in an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and natural gas tariff sales, distribution and transmission services. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of itsthe electric distribution, energy efficiency, and transmission revenue impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they each believe are probable of approval by FERC in accordance with their formula rate mechanisms. See Note 34 — Regulatory Matters and Note 523 — Accounts ReceivableSupplemental Financial Information for furtheradditional information.
RTOs and ISOs
In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations and Comprehensive Income, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale or purchase position of Exelon in the different RTOs and ISOs.
Option Contracts, Swaps and Commodity Derivatives
Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability onin its Consolidated Balance Sheets. Refer toSee Note 34 — Regulatory Matters and Note 12 — Derivative Financial Instruments for furtheradditional information.
Income Taxes (All Registrants)
Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, the Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense or Other income and
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
deductions (interest income) and recognize penalties related to unrecognized tax benefits in Other, net on their Consolidated Statements of Operations and Comprehensive Income.
In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting 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 in the Consolidated Statements of Operations and Comprehensive Income. GAAP does not address 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 their 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 year ended December 31, 2015 was $34 million and $4 million for PHI and Pepco, respectively. The impact on all other PHI Registrants for the year ended December 31, 2015 was less than $1 million.
Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for further information.
Taxes Directly Imposed on Revenue-Producing Transactions (All Registrants)
Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See See Note 2423 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes that are presented on a gross basis.
Income Taxes (All Registrants)
Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense or Other income and deductions (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.
Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for additional information.
Cash and Cash Equivalents (All Registrants)
The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents (All Registrants)
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2018 and 2017, and 2016, Exelon Corporate’sthe Registrants' restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Generation’s restricted cash and cash equivalents primarily included cash at various project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities, see Note 13 — Debt and Credit Agreements for additional information on Generation’s project- specific financing structures. ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and certain funds set aside for the remediation of one of ComEd's MGP sites. PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. BGE’s restricted cash primarily represented funds restricted for certain energy conservation incentive programs. PHI Corporate's restricted cash and cash equivalents primarily represented funds restricted for the paymentfollowing items:
|
| |
Registrant | Description |
Exelon | Payment of medical, dental, vision and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants. |
Generation | Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. |
ComEd | Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site. |
PECO | Proceeds from the sales of assets that were subject to PECO’s mortgage indenture. |
BGE | Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers. |
PHI | Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts and repayment of transition bonds. |
Pepco | Payment of merger commitments and collateral held from energy suppliers. |
DPL | Collateral held from energy suppliers. |
ACE | Repayment of transition bonds and collateral held from energy suppliers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
of merger commitments and cash collateral held from its utility suppliers. Pepco's restricted cash and cash equivalents primarily represented funds restricted for the payment of merger commitments and collateral held from its utility suppliers. DPL's restricted cash and cash equivalents primarily represented cash collateral held from suppliers associated with procurement contracts. ACE's restricted cash and cash equivalents primarily represented funds restricted at its consolidated variable interest entity for repayment of transition bonds and cash collateral held from suppliers.
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2018 and 2017, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of transition bonds.
See Note 23 — Supplemental Financial Information for additional information.
Allowance for Uncollectible Accounts (All Registrants)
The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. ComEd, PECO, BGE, Pepco, DPL and ACEUtility Registrants estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are comprised based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. Utility Registrants' customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU regulations. See Note 34 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd and ACE.
Variable Interest Entities (All Registrants)
Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes the following specific requirements:
requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest, meaning (1) has the power to direct the activities that most significantly impact the VIE's economic performance, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and
requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
See Note 2 — Variable Interest Entities for additional information.
Inventories (All Registrants)
Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fossil Fuel
Fossil fuel, inventory includes natural gas held in storage, propanematerials and oil. The costs of natural gas, propanesupplies, and oilemissions allowances are generally included in inventory when purchasedpurchased. Fossil fuel and chargedemissions allowances are expensed to purchased power and fuel expense at weighted average cost when used or sold.
Materials and Supplies
Materials and supplies inventory generally includes transmission, distribution and generating plant materials. Materialsmaterials and are generally chargedexpensed to inventory when purchasedoperating and expensedmaintenance or capitalized to property, plant and equipment, as appropriate, at weighted average cost when installed or used.
Emission AllowancesDebt and Equity Security Investments (Exelon and Generation)
Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and charged to purchased power and fuel expense at weighted average cost as they are used in operations.
Marketable Securities (All Registrants)
All marketableDebt Security Investments. Debt securities are reported at fair value. Marketablevalue and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.
Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.
Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified as tradingequity securities and all other securities are classified as available-for-sale securities.with readily determinable fair values. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO and in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Unrealized gainsExelon's and losses, net of tax, for Exelon's available-for-sale securities are reported in OCI. Exelon’s and Generation’sGeneration's NDT funds which are designated to satisfy future decommissioning obligations, are classified as eithercurrent or noncurrent or current assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. Beginning January 1, 2018, the authoritative guidance eliminates the available-for-sale classification for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings. The new authoritative guidance does not impact the classification or measurement of investments in debt securities. See Note 34 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 11 —
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair Value of Financial Assets and Liabilities and Note 15 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.
Property, Plant and Equipment (All Registrants)
Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate and PHI and AFUDC for regulated property at ComEd, PECO, BGE, Pepco, DPL and ACE.the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.
Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant and equipment.equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred.
For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.
See Note 6 — Property, PlantCapitalized Software. Certain costs, such as design, coding, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 24 — Supplemental Financial Information for additional information regarding property, plant and equipment.
Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. Certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 23 — Commitments and Contingencies for additional information regarding the SNF disposal fee.
Nuclear Outage Costs (Exelon and Generation)
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant and equipment (based on the nature of the activities) in the period incurred.
New Site Development Costs (Exelon and Generation)
New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is economically and operationally feasible, management and/or the Exelon Board of Directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. As of December 31, 2017 and 2016, Generation has capitalized $228 million and $1.7 billion, respectively, to Property, plant and equipment, net on its Consolidated Balance Sheets. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. New site development costs incurred prior to a project’s completion being deemed probable are expensed as incurred. Approximately $4 million, $30 million and $22 million of costs were expensed by Exelon and Generation for the years ended December 31, 2017, 2016 and 2015, respectively. These costs are primarily related to the possible development of new power generating facilities with the exception of
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
approximately $13 million of costs expensed in 2016 which relate to projects for which completion is no longer probable.
Capitalized Software Costs (All Registrants)
Coststesting incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant and equipment. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The following table presents net unamortizedrates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
See Note 6 — Property, Plant and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.
Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized softwarewithin Property, plant and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22 — Commitments and amortizationContingencies for additional information regarding the cost of capitalized software costs by year:SNF storage and disposal.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net unamortized software costs | | | | | | | | | | | Successor | | | | | | |
Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2017 | $ | 834 |
| | $ | 173 |
| | $ | 227 |
| | $ | 111 |
| | $ | 179 |
| | $ | 133 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
December 31, 2016 | 808 |
| | 173 |
| | 213 |
| | 91 |
| | 164 |
| | 153 |
| | 1 |
| | 1 |
| | 1 |
|
Nuclear Outage Costs (Exelon and Generation) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of capitalized software costs | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
2017 | $ | 270 |
| | $ | 73 |
| | $ | 73 |
| | $ | 39 |
| | $ | 46 |
| | $ | — |
| | $ | — |
| | $ | — |
|
2016 | 255 |
| | 72 |
| | 62 |
| | 33 |
| | 44 |
| | — |
| | — |
| | — |
|
2015 | 208 |
| | 73 |
| | 47 |
| | 33 |
| | 46 |
| | (2 | ) | | — |
| | — |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
Amortization of capitalized software costs | $ | 34 |
| | $ | 29 |
| | | $ | 8 |
| | $ | 36 |
|
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant and equipment (based on the nature of the activities) in the period incurred.Depreciation and Amortization (All Registrants)
Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. The estimated service lives for the Utility Registrants are primarily based on each company's most recenta combination of depreciation studies, historical retirements, site licenses and management estimates of historical asset retirementoperating costs and removal cost experience. At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. For its nuclear generating facilities, except for Oyster Creek, Clinton and TMI, Generation estimates each unit will operate through the full term of its initial 20-year operating license renewal period.conditions. See Note 8 — Early Nuclear Plant Retirements for additional information on the impacts of expected and potential early plant retirements. The estimated service lives of Generation's hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of 40 years.retirements.
See Note 6 — Property, Plant and Equipment for furtheradditional information regarding depreciation.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE'sthe Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.
Amortization of income tax related regulatory assets and liabilities areis generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
See Note 34 — Regulatory Matters and Note 2423 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel Generation’sand ARC, and the amortization of the Utility Registrants' regulatory assets.
Asset Retirement Obligations (All Registrants)
The authoritative guidance for accounting for AROs requires the recognition ofGeneration estimates and recognizes a liability for aits legal obligation to perform an asset retirement activityactivities even though the timing and/or methodmethods of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic future cash flow models and discount rates.events. Generation generally updates its nuclear decommissioning 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 variousthe multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning scenarios. Decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclear plant). As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years unless circumstances warrant more frequent updates. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimated undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 15 — Asset Retirement Obligations for additional information.
Capitalized Interest and AFUDC (All Registrants)
During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
2017 | Total incurred interest(a) | $ | 1,658 |
| | $ | 502 |
| | $ | 369 |
| | $ | 130 |
| | $ | 111 |
| | $ | 133 |
| | $ | 54 |
| | $ | 64 |
|
| Capitalized interest | 63 |
| | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 108 |
| | — |
| | 20 |
| | 12 |
| | 22 |
| | 34 |
| | 10 |
| | 9 |
|
2016 | Total incurred interest(a) | $ | 1,678 |
| | $ | 472 |
| | $ | 469 |
| | $ | 127 |
| | $ | 114 |
| | $ | 137 |
| | $ | 52 |
| | $ | 65 |
|
| Capitalized interest | 108 |
| | 107 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 98 |
| | — |
| | 22 |
| | 11 |
| | 30 |
| | 29 |
| | 7 |
| | 9 |
|
2015 | Total incurred interest(a) | $ | 1,170 |
| | $ | 445 |
| | $ | 336 |
| | $ | 116 |
| | $ | 113 |
| | $ | 131 |
| | $ | 51 |
| | $ | 65 |
|
| Capitalized interest | 79 |
| | 79 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 44 |
| | — |
| | 9 |
| | 7 |
| | 28 |
| | 19 |
| | 2 |
| | 2 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
Total incurred interest(a) | $ | 263 |
| | $ | 207 |
| | | $ | 68 |
| | $ | 289 |
|
Credits to AFUDC debt and equity | 54 |
| | 35 |
| | | 10 |
| | 23 |
|
__________
| |
(a) | Includes interest expense to affiliates. |
Guarantees (All Registrants)
The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
amortization method over the term of the guarantee. See Note 2322 — Commitments and Contingencies for additional information.
Asset Impairments
Long-Lived Assets (All Registrants)
Long-Lived Assets
. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value.
Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). See Note 7 — Impairment of Long-Lived Assets and Intangibles for additional information.
Goodwill
(Exelon, ComEd and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or inon an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10 — Intangible Assets for additional information regarding Exelon’s, Generation's, ComEd’s, PHI's and DPL's goodwill.information.
Equity Method Investments
(Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.
Debt and Equity Security Investments
(Exelon and Generation). Declines in the fair value of Exelon's debt and equitysecurity investments below the cost basis are reviewed to determine if such decline is other-than-temporary. For available-for-sale securities and cost investments, ifIf the decline is determined to be other-than-temporary, the cost basis is written down to fair value as a new cost basis. For equity securities and cost investments, the amount of the impairment loss is included in earnings. For debt securities, the amount of the impairment loss is included in earnings or separated between earnings
Equity Security Investments (Exelon and OCI depending on whether Exelon intends to sell the debt securities before recovery of its cost basis. Beginning January 1, 2018, the authoritative guidance eliminates the available-for-sale and cost method classifications for equity securities and requires that all equityGeneration). Equity investments (other than those accounted for using the equity method of accounting) bewith readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values must beare qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist.period. If fair value is less than carrying value, the impairment is recorded through earnings immediately in the period in which it is identified without regarddetermined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to whether the decline in value is temporary in nature. The new authoritative guidance does not impactamount by which the classification or measurement of investments in debt securities.security’s carrying amount exceeds its fair value.
Derivative Financial Instruments (All Registrants)
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally,For derivatives that qualify and are designated for hedge accounting are classifiedintended to serve as either hedges of the fair value of a
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair valueeconomic hedges, changes in fair values for both the derivative and the underlying hedged exposurevalue are recognized in earnings each period. For cash flow hedges,Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense or Other, net in the portionConsolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended toderivatives serve as economic hedges, and thatthere are not designated or do not qualifyalso derivatives entered into for hedge accounting or the normal purchasesproprietary trading purposes, subject to Exelon’s Risk Management Policy, and normal sales exception, changes in the fair value of thethose derivatives are recognizedrecorded in earnings each period, except forrevenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, where changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. See Note 3 — Regulatory Matters and Note 12 — Derivative Financial Instruments for additional information. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statements of Operations and Comprehensive Income. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. See Note 4 — Regulatory Matters and Note 12 — Derivative Financial Instruments for additional information.
As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12 — Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.
The measurement of the plan obligations and costs of providing benefits under these plans involve various factors including numerous assumptions, and inputs and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2018: In 2018, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
Defined Benefit Plan Disclosures (Issued August 2018). Eliminates existing disclosure requirements related to amounts in Accumulated other comprehensive income expected to be recognized in Net periodic benefit cost over the next year and the effects of a one-percentage-point change in the assumed health care cost trend rates. In addition, new disclosures were added such as the weighted-average interest crediting rates for cash balance plans and an explanation for the reasons for significant gains and losses related to changes in the benefit obligation. The standard is effective January 1, 2021, with early adoption permitted, and must be applied retrospectively. Exelon early adopted this standard in the fourth quarter of 2018. See Note 16 — Retirement Benefits for additional information.
Fair Value Measurement Disclosures (Issued August 2018). Updates the disclosure requirements for fair value measurements to improve the usefulness of information for financial statement users. The guidance removes the requirements to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements and adds a requirement to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The standard is effective January 1, 2020, with early adoption permitted. The amendments to remove disclosures must be applied retrospectively and can be early adopted, while the amendments to add disclosures must be applied prospectively and adoption can be delayed until the effective date. The Registrants early adopted, in the fourth quarter of 2018, the amendments to remove disclosures and will adopt the amendments to add disclosures in the first quarter of 2020. The impact of the new disclosures is not expected to be material to the Registrants’ consolidated financial statements. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018). Provides an election for a reclassification from AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early adopted this standard and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity Investment Earnings (Losses)related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation or the Utility Registrants. Exelon's accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire pension or OPEB plan is liquidated or terminated. See Note 21— Changes in Accumulated Other Comprehensive Income for additional information.
Improving the Presentation of Unconsolidated Affiliates (ExelonNet Periodic Pension Cost and Generation)
ExelonNet Periodic Postretirement Benefit Cost (Issued March 2017). Changes the accounting and Generation include equity in earnings from equity method investments in qualifying facilitiespresentation of pension and power projects in Equity in earnings (losses)OPEB costs at the plan sponsor (i.e., Exelon) level. The guidance requires plan sponsors to report the service cost and other non-service cost components of unconsolidated affiliates within their Consolidated Statements of Operationsnet periodic pension cost and Comprehensive Income.net periodic OPEB cost (together, net benefit cost) separately. Under the new guidance,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New Accounting Standards (All Registrants)
New Accounting Standards Issuedservice cost is presented as part of income from operations and Adopted asthe other non-service cost components are classified outside of January 1, 2018:The following new authoritative accounting guidance issued by the FASB has been adopted as of January 1, 2018 and will be reflected by the Registrants in their consolidated financial statements beginningincome from operations in the first quarter of 2018. Unless otherwise indicated, adoption of the new guidance in each instance will have no or insignificant impacts on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization on a prospective basis beginning on January 1, 2018. Under prior GAAP, the total amount of net benefit cost was recorded as part of income from operations and all components were eligible for capitalization. Exelon applied the presentation of the service component and the other non-service cost components of net benefit costs retrospectively and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income Consolidated Statementsin prior periods presented. Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. In Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework were prospectively reported as regulatory assets (previously, they were capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets are amortized outside of operating income. See Note 16 — Retirement Benefits for additional information.
Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting was not impacted by this standard; therefore, Exelon's subsidiary financial statements did not change upon its adoption.
Statement of Cash Flows, Consolidated Balance SheetsFlows: Classification of Restricted Cash (Issued November 2016). The standard states that amounts generally described as restricted cash and disclosures.
Revenue from Contractsrestricted cash equivalents should be included with Customers (Issued May 2014cash and subsequently amended to address implementation questions; Adopted January 1, 2018): Changescash equivalents when reconciling 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 beginningbeginning-of-period and end-of-period total amounts shown 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 did not early adopt this 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 objectivestatement 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 transfercash flows (instead of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the relatedbeing presented as cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method)flow activities). The Registrants will applyapplied the new guidance using the full retrospective method which will notand, accordingly, have a material impact on previously issued financial statements.
In coordination withrecasted the AICPA Power and Utilities Industry Task Force, the Registrants reached conclusions on the following key accounting issues:
The Utility Registrants’ tariff sale contracts, including those with lower credit quality customers, are generally deemed to be probablepresentation of collection under the guidance and, thus, the timing of revenue recognition will continue to be concurrent with the delivery of electricity or natural gas, consistent with current practice;
Consistent with current industry practice, revenues recognized from sales of bundled energy commodities (i.e., contracts involving the delivery of multiple energy commodities such as electricity, capacity, ancillary services, etc.) are generally expected to be recognized upon delivery to the customerrestricted cash in an amount based on the invoice price given that it corresponds directly with the value of the commodities transferred to the customer; and
Contributions in aid of construction are outside of the scope of the standard and, therefore, will continue to be accounted for as a reduction to Property, Plant, and Equipment.
In assessing the impacts of the new revenue guidance, the Registrants identified the following items that will be accounted for differently:
Costs to acquire certain contracts (e.g., sales commissions associated with retail power contracts) will be deferred and amortized ratably over the term of the contract rather than being expensed as incurred; and
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Variable consideration within certain contracts (e.g., performance bonuses) will be estimated and recognized as revenue over the term of the contract rather than being recognized when realized.
Based on an assessment of existing contracts and revenue streams, the new guidance, including the identified changes above, will not have a material impact on the amount and timing of the Registrants’ revenue recognition.
One of the new disclosure requirements is to present disaggregated revenue into categories that show how economic factors affect the nature, amount, timing, and uncertainty of revenue and cash flows. In order to comply with this new disclosure requirement, Generation will disclose disaggregated revenue by operating segment and provide further differentiation by major products (i.e., electric power and gas) and the Utility Registrants will disclose disaggregated revenue by major customer class (i.e., residential and commercial and industrial) separately for electric and gas in the Combined Notes to Consolidated Financial Statements. In addition, pursuant to the requirements of the new standard, Exelon and the Utility Registrants will present alternative revenue program revenue separately from revenue from contracts with customers on the face of their Consolidated Statements of Operations and Comprehensive Income.Cash Flows in the prior periods presented. See Note 23 — Supplemental Financial Information for additional information.
Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016; Adopted January 1, 2018):2016). Eliminates the available-for-sale and cost method classification for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings and, for equity investments without a readily determinable fair value, provides a measurement alternative of cost less impairment plus or minus adjustments for observable price changes in identical or similar assets. In addition, equity investments without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist. If fair value is less than carrying value, the impairment is recorded through net income immediately in the period in which it is identified. The guidance does not impact the classification or measurement of investments in debt securities. The guidance also amends several disclosure requirements, including requiring i) financial assets and financial liabilities to be presented separately in the balance sheet or note, grouped by measurement category and form, ii) disclosure of the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and iii) for financial assets and liabilities measured at amortized cost, disclosure of the fair value of the amount that would be received to sell the asset or paid to transfer the liability. The guidance is effective January 1, 2018 and must bewas applied using a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants recorded an insignificant adjustment to opening retained earnings as of January 1, 2018 related to unrealized gains/losses on available for sale equity securities. See Note 21— Changes in Accumulated Other Comprehensive Income for additional information.
Statement of Cash Flows: Classification of Certain Cash ReceiptsRevenue from Contracts with Customers (Issued May 2014 and Cash Payments (Issued August 2016; Adopted January 1, 2018) and Restricted Cash (Issued November 2016; Adopted January 1, 2018):subsequently amended to address implementation questions). In 2016,Changes the FASB issued two standards impacting the Statement of Cash Flows.criteria for recognizing revenue from a contract with a customer. The first adds or clarifiesnew 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 classificationnew 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 certain cash receiptsgoods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and payments on the statementuncertainty of cash flows as follows: debt prepayment or extinguishment costs, settlement of zero-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,revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the predominance principle to separately identifiable cash flows.guidance at the date of initial adoption (modified retrospective method). The second states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconcilingRegistrants applied the beginning-of-period and end-of-period total amounts shown onnew guidance using the statement of cash flows (instead of being presented asfull retrospective method
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
cash flow activities). The new standards are effective on January 1, 2018 and, must be applied on a full retrospective basis. Adoptionaccordingly, have recasted certain amounts in their Consolidated Statements of the second standard will result in a change in presentation of restricted cash on the face of the StatementOperations and Comprehensive Income, Consolidated Statements of Cash Flows; otherwise this guidance will not have a significant impact onFlows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements in the prior periods presented. The amounts recasted in the Registrants' 2017 and 2016 Consolidated Statements of Operations and Comprehensive Income are shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, and disclosures.
Intra-Entity Transfers of Assets Other Than Inventory (Issued October 2016; Adopted January 1, 2018):Requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs (current GAAP 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 January 1, 2018 with early adoption permitted. The guidance requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption.
Clarifying the Definition of a Business (Issued January 2017; Adopted January 1, 2018):Clarifies the definition of a business with the objective of addressing whether acquisitions (or dispositions) should be accounted for as acquisitions/dispositions of assets or as acquisitions/dispositions of businesses. If substantially all the fair value of the assets acquired/disposed of 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/disposed of 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 will likely result in more acquisitions being accounted for as asset acquisitions. The standard is effective January 1, 2018, with early adoption permitted, and must be applied on a prospective basis. The Registrants did not early adopt the guidance.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017; Adopted January 1, 2018):Changes the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. The guidance requires plan sponsors to report the service cost and other non-service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under the new guidance, service cost is presented as part of income from operations and the other non-service cost components are classified outside of income from operations on theConsolidated Balance Sheets, Consolidated Statements of OperationsChanges in Shareholders' Equity and Comprehensive Income. Additionally, service cost is the only component eligibleCombined Notes to Consolidated Financial Statements were not material. See Note 3 — Revenue from Contracts with Customers for capitalization. Under prior GAAP, the total amount of net benefit cost was recorded as part of income from operations and all components were eligible for capitalization.
Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting is not impacted by this standard; therefore, Exelon's subsidiary financial statements will not change upon its adoption. On Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework are prospectively reported as regulatory assets (currently, they are capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets are amortized outside of operating income.
The presentation of the service cost component and the other non-service cost components of net benefit cost will be applied retrospectively in the Exelon consolidated financial statements beginning in the first quarter of 2018. On Exelon's consolidated financial statements, service cost will continue to be reported in Operating and maintenance and Non-service cost will be reported outside of operating income. The prospective change in the capitalization eligibility is not expected to have a significant impact on Exelon’s consolidated net income.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2017: The following new authoritative accounting guidance issued by the FASB has not yet been adopted andadditional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
For the year ended December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Operating Revenues - As reported | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 17,360 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Rate-regulated utility revenues | 16,171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Operating revenues | — |
| | 17,351 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric operating revenues | — |
| | — |
| | 5,521 |
| | 2,369 |
| | 2,484 |
| | 4,468 |
| | 2,152 |
| | 1,131 |
| | 1,184 |
|
Natural gas operating revenues | — |
| | — |
| | — |
| | 494 |
| | 676 |
| | 161 |
| | — |
| | 161 |
| | — |
|
Operating revenues from affiliates | — |
| | 1,115 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 6 |
| | 8 |
| | 2 |
|
Total operating revenues | $ | 33,531 |
| | $ | 18,466 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
| | | | | | | | | | | | | | | | | |
Operating Revenues - Adjustments | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Rate-regulated utility revenues | (207 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Operating revenues | — |
| | 34 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric operating revenues | — |
| | — |
| | (43 | ) | | — |
| | (100 | ) | | (40 | ) | | (26 | ) | | (6 | ) | | (8 | ) |
Natural gas operating revenues | — |
| | — |
| | — |
| | — |
| | (24 | ) | | — |
| | — |
| | — |
| | — |
|
Revenues from alternative revenue programs | 207 |
| | — |
| | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
Operating revenues from affiliates | — |
| | — |
| | — |
| | — |
| |
|
| | — |
| | — |
| | — |
| | — |
|
Total operating revenues | $ | 34 |
| | $ | 34 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| | | | | | | | | | | | | | | | | |
Operating Revenues - Retrospective application | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 17,394 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Rate-regulated utility revenues | 15,964 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Operating revenues | — |
| | 17,385 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric operating revenues | — |
| | — |
| | 5,478 |
| | 2,369 |
| | 2,384 |
| | 4,428 |
| | 2,126 |
| | 1,125 |
| | 1,176 |
|
Natural gas operating revenues | — |
| | — |
| | — |
| | 494 |
| | 652 |
| | 161 |
| | — |
| | 161 |
| | — |
|
Revenues from alternative revenue programs | 207 |
| | — |
| | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
Operating revenues from affiliates | — |
| | 1,115 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 6 |
| | 8 |
| | 2 |
|
Total operating revenues | $ | 33,565 |
| | $ | 18,500 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | | | | | | | | | | | | | | | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
For the year ended December 31, 2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Operating Revenues - As reported | | | | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 16,324 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
Rate-regulated utility revenues | 15,036 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Operating revenues | — |
| | 16,312 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Electric operating revenues | — |
| | — |
| | 5,239 |
| | 2,524 |
| | 2,603 |
| | 2,181 |
| | 1,122 |
| | 1,254 |
| | 3,506 |
| | | 1,096 |
|
Natural gas operating revenues | — |
| | — |
| | — |
| | 462 |
| | 609 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
Operating revenues from affiliates | — |
| | 1,439 |
| | 15 |
| | 8 |
| | 21 |
| | 5 |
| | 7 |
| | 3 |
| | 45 |
| | | — |
|
Total operating revenues | $ | 31,360 |
| | $ | 17,751 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
| | | | | | | | | | | | | | | | | | | | |
Operating Revenues - Adjustments | | | | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
Rate-regulated utility revenues | (48 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Operating revenues | — |
| | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Electric operating revenues | — |
| | — |
| | 24 |
| | — |
| | (72 | ) | | (14 | ) | | 6 |
| | (9 | ) | | (43 | ) | | | 26 |
|
Natural gas operating revenues | — |
| | — |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Revenues from alternative revenue programs | 48 |
| | — |
| | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
Operating revenues from affiliates | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total operating revenues | $ | 6 |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
| | | | | | | | | | | | | | | | | | | | |
Operating Revenues - Retrospective application | | | | | | | | | | | | | | | | | | | | |
Competitive business revenues | $ | 16,330 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
Rate-regulated utility revenues | 14,988 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Operating revenues | — |
| | 16,318 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Electric operating revenues | — |
| | — |
| | 5,263 |
| | 2,524 |
| | 2,531 |
| | 2,167 |
| | 1,128 |
| | 1,245 |
| | 3,463 |
| | | 1,122 |
|
Natural gas operating revenues | — |
| | — |
| | — |
| | 462 |
| | 628 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
Revenues from alternative revenue programs | 48 |
| | — |
| | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
Operating revenues from affiliates | — |
| | 1,439 |
| | 15 |
| | 8 |
| | 21 |
| | 5 |
| | 7 |
| | 3 |
| | 45 |
| | | — |
|
Total operating revenues | $ | 31,366 |
| | $ | 17,757 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New Accounting Standards Adopted as of January 1, 2019: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2019 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2019.
Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard is effective January 1, 2020, with early adoption permitted, and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance is not expected to have a material impact on the Registrants’ financial statements.
Leases (Issued February 2016). Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The Registrants adopted the standard on January 1, 2019.
The new standard requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas under previous GAAP only finance lease liabilities (referred to as capital leases) were recognized in the balance sheet. In addition, the definition of a lease has been revised which may result in changes to the classification of an arrangement as a lease. Under the new standard, an arrangement that conveys the right to control the use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the previous definition focuses on the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas previous disclosures related only to lessees. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. Lessor accounting is also largely unchanged.
The new standard provides a number of transition practical expedients, which the Registrants have elected, including:
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and
a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously accounted for as leases.
The Registrants have assessed the lease standard and executed a detailed implementation plan in preparation for adoption, which included the following key activities:
Developed a complete lease inventory and abstracted the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.
Evaluated the transition practical expedients available under the standard.
Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.
Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.
The adoption of the new standard is expected to result in right of use assets and lease obligations for operating leases recorded in the Registrants’ Consolidated Balance Sheets on January 1, 2019 of approximately:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | |
| Exelon | Generation | ComEd | PECO | BGE | PHI | Pepco | DPL | ACE |
ROU Assets | $1,400-$1,500 | $1,000-$1,100 | $5-$10 | $1-$5 | $100-$120 | $250-$270 | $60-$65 | $70-$75 | $20-$25 |
Lease Liabilities | $1,600-$1,700 | $1,200-$1,300 | $5-$10 | $1-$5 | $100-$120 | $300-$320 | $60-$65 | $75-$80 | $20-$25 |
The impact of adopting the new standard on retained earnings as of January 1, 2019 is expected to be immaterial.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2018: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2017.2018. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) onin their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that such standards will not significantly impact the Registrants' financial reporting.
LeasesGoodwill Impairment (Issued February 2016):January 2017).Increases transparency Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and comparability among organizations by recognizing lease assets and lease liabilities onDPL have goodwill as of December 31, 2018. This updated guidance is not currently expected to impact the balance sheet and disclosing key information about leasing arrangements.Registrants’ financial reporting. The standard is effective January 1, 2019. Early2020, with early adoption is permitted, however the Registrants will not early adopt the standard. The issued guidance required a modified retrospective transition approach, which requires lessees and lessors to recognize and measure leases at the beginning of the earliest period presented (January 1, 2017). In January 2018, the FASB proposed amending the standard to give entities another option for transition. The proposed transition method would allow entities to initially apply the requirements of the standard in the period of adoption (January 1, 2019). The Registrants will assess this transition option when the FASB issues the standard.
The new guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only finance lease liabilities (referred to as capital leases) are recognized in the balance sheet. In addition, the definition of a lease has been revised when an arrangement conveys the right to control the use of the identified asset which may change the classification of an arrangement as a lease. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s accounting for leases and the related cash flows are also expanded. Disclosure requirements apply to both lessees and lessors, whereas current disclosures relate only to lessees. Significant changes to lease systems, processes and procedures are required to implement the requirements of the new standard. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. Lessor accounting is also largely unchanged.
The standard provides a number of transition practical expedients that entities may elect. These include a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In January 2018, the FASB issued additional guidance which provides another optional transition practical expedient. This practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases.
The Registrants have assessed the lease standard and are executingapplied on a detailed implementation plan in preparation for adoption on January 1, 2019. Key activities in the implementation plan include:
Developing a complete lease inventory and abstracting the required data attributes into a lease accounting system that supports the Registrants' lease portfolios and integrates with existing systems.
Evaluating the transition practical expedients available under the guidance.
Identifying, assessing and documenting technical accounting issues, policy considerations and financial reporting implications. Includes completing a detailed contract assessment for a sample of transactions to determine whether they are leases under the new guidance.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Identifying and implementing changes to processes and controls to ensure all impacts of the new guidance are effectively addressed.
Accounting and implementation issues continue to be identified and evaluated by the implementation team.prospective basis.
Impairment of Financial Instruments (Issued June 2016):.Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. 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 (with early adoption as of January 1, 2019 permitted) 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, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI, and DPL have goodwill as ofDecember 31, 2017. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be applied on a prospective basis.
Derivatives and Hedging (Issued September 2017):Allows more financial and nonfinancial hedging strategies to be eligible for hedge accounting. The amendments are intended to more closely align hedge accounting with companies’ risk management strategies, simplify the application of hedge accounting, and increase transparency as to the scope and results of hedging programs. There are also amendments related to effectiveness testing and disclosure requirements. The guidance is effective January 1, 2019 and early adoption is permitted with a modified retrospective transition approach. The Registrants are currently assessing this standard but do not currently expect a significant impact given the limited activity for which the Registrants elect hedge accounting and because the Registrants do not anticipate increasing their use of hedge accounting as a resultimpacts of this standard.
2. 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 December 31, 2018 and 2017, Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was the primary beneficiary. At 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 ((see see Consolidated Variable Interest Entities below). As of December 31, 20172018 and 2016,2017, Exelon and Generation collectively had significant interests in seven and eight 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).
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest Entities below).
Consolidated Variable Interest Entities
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at December 31, 20172018 and 20162017 are as follows:
| | | December 31, 2017 | | | | | | | | | |
| | | | | Successor | | | December 31, 2018 |
| Exelon(a) | | Generation | | PHI(a) | | ACE | Exelon(a) | | Generation | | PHI(a) | | ACE |
Current assets | $ | 630 |
| | $ | 620 |
| | $ | 10 |
| | 6 |
| $ | 938 |
| | $ | 931 |
| | $ | 7 |
| | 4 |
|
Noncurrent assets | 9,317 |
| | 9,286 |
| | 31 |
| | 23 |
| 9,071 |
| | 9,045 |
| | 26 |
| | 19 |
|
Total assets | $ | 9,947 |
|
| $ | 9,906 |
|
| $ | 41 |
|
| $ | 29 |
| $ | 10,009 |
|
| $ | 9,976 |
|
| $ | 33 |
|
| $ | 23 |
|
Current liabilities | $ | 306 |
| | $ | 270 |
| | $ | 36 |
| | 32 |
| $ | 274 |
| | $ | 252 |
| | $ | 22 |
| | 19 |
|
Noncurrent liabilities | 3,312 |
| | 3,246 |
| | 66 |
| | 58 |
| 3,280 |
| | 3,233 |
| | 47 |
| | 40 |
|
Total liabilities | $ | 3,618 |
|
| $ | 3,516 |
|
| $ | 102 |
|
| $ | 90 |
| $ | 3,554 |
|
| $ | 3,485 |
|
| $ | 69 |
|
| $ | 59 |
|
| | | December 31, 2016 | | | | | | | | | |
| | | | | | | Successor | | | December 31, 2017 |
| Exelon(a)(b) | | Generation | | BGE | | PHI(a) | | ACE | Exelon(a) | | Generation | | PHI(a) | | ACE |
Current assets | $ | 954 |
| | $ | 916 |
| | $ | 23 |
| | $ | 14 |
| | $ | 9 |
| $ | 662 |
| | $ | 652 |
| | $ | 10 |
| | $ | 6 |
|
Noncurrent assets | 8,563 |
| | 8,525 |
| | 3 |
| | 35 |
| | 23 |
| 9,317 |
| | 9,286 |
| | 31 |
| | 23 |
|
Total assets | $ | 9,517 |
| | $ | 9,441 |
| | $ | 26 |
| | $ | 49 |
| | $ | 32 |
| $ | 9,979 |
| | $ | 9,938 |
| | $ | 41 |
| | $ | 29 |
|
Current liabilities | $ | 885 |
| | $ | 802 |
| | $ | 42 |
| | $ | 42 |
| | $ | 37 |
| $ | 308 |
| | $ | 272 |
| | $ | 36 |
| | $ | 32 |
|
Noncurrent liabilities | 2,713 |
| | 2,612 |
| | — |
| | 101 |
| | 89 |
| 3,316 |
| | 3,250 |
| | 66 |
| | 58 |
|
Total liabilities | $ | 3,598 |
| | $ | 3,414 |
| | $ | 42 |
| | $ | 143 |
| | $ | 126 |
| $ | 3,624 |
| | $ | 3,522 |
| | $ | 102 |
| | $ | 90 |
|
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
| |
(b) | Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. |
Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be settled using VIE resources.
As of December 31, 2018 and 2017, Exelon's and Generation's consolidated VIEs consist of:
Investments in Other Energy Related Companies
During 2015, Generation sold 69% of its equity interest in a company to a tax equity investor. The company holds an equity method investment in a distributed energy company that is an unconsolidated VIE (see unconsolidated VIE section for additional details). Generation and the tax equity investor contributed a total of $227 million of equity in proportion to their ownership interests to the company. The company meets the definition of a VIE because it has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. Generation is the primary beneficiary because Generation manages the day-to-day activities of the entity.
During 2015, Generation formed a limited liability company to build, own, and operate a backup generator. While Generation owns 100% of the backup generator company, it was determined that the entity is a VIE because the customer absorbs price variability from the entity through the fixed price
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
backup generator agreement. Generation provides operating and capital funding to the backup generator company.
During the fourth quarter of 2017 Generation acquired a controlling financial interest in an energy development company. The company is in the development stage and requires additional subordinated financial support from the equity holders to fund activities. Generation is the majority owner with a 62% equity interest and has the power to direct the activities that most significantly affect the economic performance of the company.
Renewable Energy Project Companies
In July 2017, Generation entered into an arrangement to sellsold a 49% interest in ExGen Renewable Partners, LLC (the Renewable JV)EGRP to an outside investor for $400 million of cash plus immaterial working capital and other customary post-closing adjustments. The Renewable JVEGRP meets the definition of a VIE because the Renewable JVEGRP has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generation is the primarilyprimary beneficiary because Generation manages the day-to-day activities of the entity; therefore, Generation will continue to consolidate the Renewable JV. The Renewable JVEGRP. EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by the Renewable JV.EGRP. The details relating to these VIEs are discussed below.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by the Renewable JV.EGRP. While Generation or the Renewable JVEGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related to Generation related to certain solar and wind entities.
While Generation or the Renewable JVEGRP owns 100% of the majority of the wind entities, sixfour of the projects have noncontrolling equity interests of 1% held by third parties and one of the projects has noncontrolling equity interests related to its Class B Membership Interest (see additional details below). The entities with noncontrolling equity interests of 1% held by third parties meet the definition of a VIE because the entities have noncontrolling equity interest holders that absorb variability from the wind projects. Generation’s or the Renewable JV'sEGRP's current economic interests in fivethree of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation or the Renewable JVEGRP are to provide financial support to the projects in proportion to its current 99% economic interests in the projects. Generation provides operating and capital funding to the wind project entities for ongoing construction, operations and maintenance and there is limited recourse to Generation related to certain wind project entities. However, no additional support to these projects beyond what was contractually required has been provided during 2017.provided. Generation is the primary beneficiary of these wind entities because Generation controls the design, construction, and operation of the facilities.
In December 2016, Generation sold 100% of the Class B Membership Interests to a tax equity investor and retained 100% of the Class A Membership Interests of its equity interest in one of its wind
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
entities that was previously consolidated under the voting interest model.model and was subsequently contributed to EGRP in 2017. The wind entity meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. While Generation is the minority interest holder, Generation is the primary beneficiary, because Generation manages the day-to-day activities of the entity. Therefore, the entity continues to be consolidated by Generation.
The renewable energyIn 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project companies VIE group was previously separated into two VIE groupsfinancing structure. Refer to Note 13 — Debt and Credit Agreements for solar project limited liability companiesadditional information on ExGen Renewables IV and wind project companies as of December 31, 2016.ITEM 2.PROPERTIES for additional details on the specific projects included within EGRP.
Retail Power and Gas Companies
In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $30$34 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs do not have a material impact on Generation’s financial results or financial condition.
CENG
CENG is a joint venture between Generation and EDF. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. As a result of executing the NOSA, CENG qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the results of operations and financial position of CENG.
Exelon and Generation, where indicated, provide the following support to CENG (see Note 26 — Related Party Transactions for additional information regarding Generation's and Exelon’s transactions with CENG):CENG:
under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 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 were suspended during the term of the Reliability Support Services Agreement (RSSA),RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017. (see Note 34 — Regulatory Matters for additional details),
Generation provided a $400 million loan to CENG. As of December 31, 2017,2018, the remaining obligation is $333$196 million, including accrued interest, which reflects the principal payment madeinterest. The remaining balance was fully paid by CENG in January 2015,2019.
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 2322 — Commitments and Contingencies for more details),
Generation and EDF share in the $637$688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
As of December 31, 2016, Exelon2018 and Generation had the following consolidated VIEs that are no longer VIEs as of December 31, 2017:
Retail Gas Group
During 2009, Constellation formed a retail gas group to enter into a collateralized gas supply agreement with a third-party gas supplier. The retail gas group was determined to be a VIE because there was not sufficient equity to fund the group’s activities without additional credit support and a $75 million parental guarantee provided by Generation. As the primary beneficiary, Generation consolidated the retail gas group. During the second quarter of 2017, the collateral structure was terminated with the third-party gas supplier except for the $75 million parental guarantee provided by Generation. Although the parental guarantee remains, this is considered customary and reasonable for the unsecured position Generation has with the third-party gas supplier. As a result of the termination, the retail gas group no longer met the definition of a VIE. However, the retail gas group continues to be consolidated by Generation under the voting interest model.
Other Generating Facilities
Prior to 2017, Generation owned 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015, the entity was deemed to be a VIE because the entity required additional subordinated financial support in the form of a parental guarantee provided by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract for the facility in support of one of its other generating facilities. During the third quarter of 2017, the ownership of the entity increased to 99%, all payment obligations related to the EPC contract were satisfied, and the parental guarantee provided by Generation was terminated. As a result, the entity is now sufficiently capitalized and no longer meets the definition of a VIE. However, the biomass facility continues to be consolidated by Generation under the voting interest model.
As of December 31, 2017 and 2016, Exelon's, PHI's and ACE's consolidated VIE consists of:
ACE Transition Funding
A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three years ended December 31, 2018, 2017 2016 and 2015,2016, ACE transferred $30 million, $48 million, $60 million and $61$60 million to ATF, respectively.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2016, Exelon2018 and BGE had the following consolidated VIE that is no longer a VIE as of December 31, 2017:
RSB BondCo LLC.
In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges were assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. In the second quarter of 2017, the rate stabilization bonds were fully redeemed and BGE remitted its final payment to BondCo. Upon redemption of the bonds, BondCo no longer meets the definition of a variable interest entity.
BondCo’s assets were restricted and could only be used to settle the obligations of BondCo. Further, BGE was required to remit all payments it received from customers for rate stabilization charges to BondCo. During 2017, 2016 and 2015, BGE remitted $22 million, $86 million and $86 million, respectively, to BondCo.
For each of the consolidated VIEs noted above, except as otherwise noted:
the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
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
the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI's or ACE's general credit.
As of December 31, 2017 and 2016, ComEd, PECO, BGE, Pepco and DPL do not have any material consolidated VIEs.
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 December 31, 20172018 and 2016,2017, these assets and liabilities primarily consisted of the following:
| | | | | December 31, 2017 | | | | | | | | | |
| | | | | | Successor | | | December 31, 2018 |
| | Exelon(a) | | Generation | | PHI(a) | | ACE | Exelon(a) | | Generation | | PHI(a) | | ACE |
Cash and cash equivalents | Cash and cash equivalents | | $ | 126 |
| | $ | 126 |
| | $ | — |
| | $ | — |
| $ | 414 |
| | $ | 414 |
| | $ | — |
| | $ | — |
|
Restricted cash |
| 64 |
| | 58 |
| | 6 |
| | 6 |
| |
Restricted cash and cash equivalents | | 66 |
| | 62 |
| | 4 |
| | 4 |
|
Accounts receivable, net | Accounts receivable, net | | | | | | | | | | | | | | | |
| Customer | | 138 |
| | 138 |
| | — |
| | — |
| |
| Other | | 25 |
| | 25 |
| | — |
| | — |
| |
Customer | | 146 |
| | 146 |
| | — |
| | — |
|
Other | | 23 |
| | 23 |
| | — |
| | — |
|
Inventory | Inventory | | | | | | | | | | | | | | | |
| Materials and supplies | | 205 |
| | 205 |
| | — |
| | — |
| |
Materials and supplies | | 212 |
| | 212 |
| | — |
| | — |
|
Other current assets | Other current assets | | 45 |
| | 41 |
| | 4 |
| | — |
| 52 |
| | 49 |
| | 3 |
| | — |
|
| Total current assets | | 603 |
|
| 593 |
|
| 10 |
|
| 6 |
| |
Total current assets | | 913 |
|
| 906 |
|
| 7 |
|
| 4 |
|
| | | | | | | | | | | | | | | |
Property, plant and equipment, net | Property, plant and equipment, net | | 6,186 |
| | 6,186 |
| | — |
| | — |
| 6,145 |
| | 6,145 |
| | — |
| | — |
|
Nuclear decommissioning trust funds | Nuclear decommissioning trust funds | | 2,502 |
| | 2,502 |
| | — |
| | — |
| 2,351 |
| | 2,351 |
| | — |
| | — |
|
Other noncurrent assets | Other noncurrent assets | | 274 |
| | 243 |
| | 31 |
| | 23 |
| 258 |
| | 232 |
| | 26 |
| | 19 |
|
| Total noncurrent assets | | 8,962 |
|
| 8,931 |
|
| 31 |
|
| 23 |
| |
| Total assets | | $ | 9,565 |
|
| $ | 9,524 |
|
| $ | 41 |
|
| $ | 29 |
| |
Total noncurrent assets | | 8,754 |
|
| 8,728 |
|
| 26 |
|
| 19 |
|
Total assets | | $ | 9,667 |
|
| $ | 9,634 |
|
| $ | 33 |
|
| $ | 23 |
|
| | | | | | | | | | | | | | | |
Long-term debt due within one year | Long-term debt due within one year | | $ | 102 |
| | $ | 67 |
| | $ | 35 |
| | $ | 31 |
| $ | 87 |
| | $ | 66 |
| | $ | 21 |
| | $ | 18 |
|
Accounts payable | Accounts payable | | 114 |
| | 114 |
| | — |
| | — |
| 96 |
| | 96 |
| | — |
| | — |
|
Accrued expenses | Accrued expenses | | 65 |
| | 64 |
| | 1 |
| | 1 |
| 72 |
| | 72 |
| | 1 |
| | 1 |
|
Unamortized energy contract liabilities | Unamortized energy contract liabilities | | 18 |
| | 18 |
| | — |
| | — |
| 15 |
| | 15 |
| | — |
| | — |
|
Other current liabilities | Other current liabilities | | 7 |
| | 7 |
| | — |
| | — |
| 3 |
| | 3 |
| | — |
| | — |
|
Total current liabilities | | 273 |
|
| 252 |
|
| 22 |
|
| 19 |
|
| Total current liabilities | | 306 |
|
| 270 |
|
| 36 |
|
| 32 |
| | | | | | | |
| | | | | | | | | |
| Long-term debt | | 1,154 |
| | 1,088 |
| | 66 |
| | 58 |
| |
| Asset retirement obligations | | 2,035 |
| | 2,035 |
| | — |
| | — |
| |
| Unamortized energy contract liabilities | | 5 |
| | 5 |
| | — |
| | — |
| |
| Other noncurrent liabilities | | 112 |
| | 112 |
| | — |
| | — |
| |
| Noncurrent liabilities | | 3,306 |
|
| 3,240 |
|
| 66 |
|
| 58 |
| |
| Total liabilities | | $ | 3,612 |
|
| $ | 3,510 |
|
| $ | 102 |
|
| $ | 90 |
| |
Long-term debt | | 1,072 |
| | 1,025 |
| | 47 |
| | 40 |
|
Asset retirement obligations | | 2,160 |
| | 2,160 |
| | — |
| | — |
|
Unamortized energy contract liabilities | | 1 |
| | 1 |
| | — |
| | — |
|
Other noncurrent liabilities | | 42 |
| | 42 |
| | — |
| | — |
|
Total noncurrent liabilities | | 3,275 |
|
| 3,228 |
|
| 47 |
|
| 40 |
|
Total liabilities | | $ | 3,548 |
|
| $ | 3,480 |
|
| $ | 69 |
|
| $ | 59 |
|
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | December 31, 2016 | | | | | | | | | |
| | | | | | | | Successor | | | December 31, 2017 |
| | Exelon(a)(b) | | Generation | | BGE | | PHI(a) | | ACE | Exelon(a) | | Generation | | PHI(a) | | ACE |
Cash and cash equivalents | Cash and cash equivalents | | $ | 150 |
| | $ | 150 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 126 |
| | $ | 126 |
| | $ | — |
| | $ | — |
|
Restricted cash | | 59 |
| | 27 |
| | 23 |
| | 9 |
| | 9 |
| |
Restricted cash and cash equivalents | | 64 |
| | 58 |
| | 6 |
| | 6 |
|
Accounts receivable, net | Accounts receivable, net | | | | | | | | | | | | | | | | | |
| Customer | | 371 |
| | 371 |
| | — |
| | — |
| | — |
| |
| Other | | 48 |
| | 48 |
| | — |
| | — |
| | — |
| |
Mark-to-market derivative assets | | 31 |
| | 31 |
| | — |
| | — |
| | — |
| |
Customer | | 170 |
| | 170 |
| | — |
| | — |
|
Other | | 25 |
| | 25 |
| | — |
| | — |
|
Inventory | Inventory | | | | | | | | | | | | | | | | | |
| Materials and supplies | | 199 |
| | 199 |
| | — |
| | — |
| | — |
| |
Materials and supplies | | 205 |
| | 205 |
| | — |
| | — |
|
Other current assets | Other current assets | | 50 |
| | 44 |
| | — |
| | 5 |
| | — |
| 45 |
| | 41 |
| | 4 |
| | — |
|
| Total current assets | | 908 |
| | 870 |
| | 23 |
| | 14 |
| | 9 |
| |
Total current assets | | 635 |
| | 625 |
| | 10 |
| | 6 |
|
| | | | | | | | | | | | | | | | | |
Property, plant and equipment, net | Property, plant and equipment, net | | 5,415 |
| | 5,415 |
| | — |
| | — |
| | — |
| 6,186 |
| | 6,186 |
| | — |
| | — |
|
Nuclear decommissioning trust funds | Nuclear decommissioning trust funds | | 2,185 |
| | 2,185 |
| | — |
| | — |
| | — |
| 2,502 |
| | 2,502 |
| | — |
| | — |
|
Goodwill | | 47 |
| | 47 |
| | — |
| | — |
| | — |
| |
Mark-to-market derivative assets | | 23 |
| | 23 |
| | — |
| | — |
| | — |
| |
Other noncurrent assets | Other noncurrent assets | | 315 |
| | 277 |
| | 3 |
| | 35 |
| | 23 |
| 274 |
| | 243 |
| | 31 |
| | 23 |
|
| Total noncurrent assets | | 7,985 |
| | 7,947 |
| | 3 |
| | 35 |
| | 23 |
| |
| Total assets | | $ | 8,893 |
| | $ | 8,817 |
| | $ | 26 |
| | $ | 49 |
| | $ | 32 |
| |
Total noncurrent assets | | 8,962 |
| | 8,931 |
| | 31 |
| | 23 |
|
Total assets | | $ | 9,597 |
| | $ | 9,556 |
| | $ | 41 |
| | $ | 29 |
|
| | | | | | | | | | | | | | | | | |
Long-term debt due within one year | Long-term debt due within one year | | $ | 181 |
| | $ | 99 |
| | $ | 41 |
| | $ | 40 |
| | $ | 35 |
| $ | 102 |
| | $ | 67 |
| | $ | 35 |
| | $ | 31 |
|
Accounts payable | Accounts payable | | 269 |
| | 269 |
| | — |
| | — |
| | — |
| 114 |
| | 114 |
| | — |
| | — |
|
Accrued expenses | Accrued expenses | | 119 |
| | 116 |
| | 1 |
| | 2 |
| | 2 |
| 67 |
| | 66 |
| | 1 |
| | 1 |
|
Mark-to-market derivative liabilities | | 60 |
| | 60 |
| | — |
| | — |
| | — |
| |
Unamortized energy contract liabilities | Unamortized energy contract liabilities | | 15 |
| | 15 |
| | — |
| | — |
| | — |
| 18 |
| | 18 |
| | — |
| | — |
|
Other current liabilities | Other current liabilities | | 30 |
| | 30 |
| | — |
| | — |
| | — |
| 7 |
| | 7 |
| | — |
| | — |
|
Total current liabilities | | 308 |
| | 272 |
| | 36 |
| | 32 |
|
| Total current liabilities | | 674 |
| | 589 |
| | 42 |
| | 42 |
| | 37 |
| | | | | | | |
| | | | | | | | | | | |
| Long-term debt | | 641 |
| | 540 |
| | — |
| | 101 |
| | 89 |
| |
| Asset retirement obligations | | 1,904 |
| | 1,904 |
| | — |
| | — |
| | — |
| |
| Pension obligation(c) | | 9 |
| | 9 |
| | — |
| | — |
| | — |
| |
| Unamortized energy contract liabilities | | 22 |
| | 22 |
| | — |
| | — |
| | — |
| |
| Other noncurrent liabilities | | 106 |
| | 106 |
| | — |
| | — |
| | — |
| |
| Noncurrent liabilities | | 2,682 |
| | 2,581 |
| | — |
| | 101 |
| | 89 |
| |
| Total liabilities | | $ | 3,356 |
| | $ | 3,170 |
| | $ | 42 |
| | $ | 143 |
| | $ | 126 |
| |
Long-term debt | | 1,154 |
| | 1,088 |
| | 66 |
| | 58 |
|
Asset retirement obligations | | 2,035 |
| | 2,035 |
| | — |
| | — |
|
Other noncurrent liabilities | | 121 |
| | 121 |
| | — |
| | — |
|
Total noncurrent liabilities | | 3,310 |
| | 3,244 |
| | 66 |
| | 58 |
|
Total liabilities | | $ | 3,618 |
| | $ | 3,516 |
| | $ | 102 |
| | $ | 90 |
|
__________
| |
(a) | Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity. |
| |
(b) | Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity. |
| |
(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 balance sheet. See Note 16 - Retirement Benefits for additional details. |
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 onin 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.
As of December 31, 20172018 and 2016,2017, Exelon and Generation had significant unconsolidated variable interests in sevenandeight VIEs respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation hashave several individually immaterial VIEs that in aggregate represent a total investment of $8 million. These immaterial VIEs are equity$15 million and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $8$13 million, included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets.
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
|
| | | | | | | | | | | |
December 31, 2017 | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 625 |
| | $ | 509 |
| | $ | 1,134 |
|
Total liabilities(a) | 37 |
| | 228 |
| | 265 |
|
Exelon's ownership interest in VIE(a) | — |
| | 251 |
| | 251 |
|
Other ownership interests in VIE(a) | 588 |
| | 30 |
| | 618 |
|
Registrants’ maximum exposure to loss: | | | | |
|
|
Carrying amount of equity method investments | — |
| | 251 |
| | 251 |
|
Contract intangible asset | 8 |
| | — |
| | 8 |
|
Debt and payment guarantees | — |
| | — |
| | — |
|
Net assets pledged for Zion Station decommissioning(b) | 2 |
| | — |
| | 2 |
|
respectively,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
as of December 31, 2018. These immaterial VIEs are equity and debt securities in energy development companies. As of December 31, 2018, the maximum exposure to loss related to these securities included in Investments in Exelon's and Generation's Consolidated Balance Sheets is limited to the $15 million and $13 million, respectively.
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
| | December 31, 2016 | Commercial Agreement VIEs | | Equity Investment VIEs | | Total | |
December 31, 2018 | | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 638 |
| | $ | 567 |
| | $ | 1,205 |
| $ | 597 |
| | $ | 472 |
| | $ | 1,069 |
|
Total liabilities(a) | 215 |
| | 287 |
| | 502 |
| 37 |
| | 222 |
| | 259 |
|
Exelon's ownership interest in VIE(a) | — |
| | 248 |
| | 248 |
| — |
| | 223 |
| | 223 |
|
Other ownership interests in VIE(a) | 423 |
| | 32 |
| | 455 |
| 560 |
| | 27 |
| | 587 |
|
Registrants’ maximum exposure to loss: |
| |
| |
|
| | | | |
|
|
Carrying amount of equity method investments | — |
| | 264 |
| | 264 |
| — |
| | 223 |
| | 223 |
|
Contract intangible asset | 9 |
| | — |
| | 9 |
| 7 |
| | — |
| | 7 |
|
Debt and payment guarantees | — |
| | 3 |
| | 3 |
| |
Net assets pledged for Zion Station decommissioning(b) | 9 |
| | — |
| | 9 |
| — |
| | — |
| | — |
|
|
| | | | | | | | | | | |
December 31, 2017 | Commercial Agreement VIEs | | Equity Investment VIEs | | Total |
Total assets(a) | $ | 625 |
| | $ | 509 |
| | $ | 1,134 |
|
Total liabilities(a) | 37 |
| | 228 |
| | 265 |
|
Exelon's ownership interest in VIE(a) | — |
| | 251 |
| | 251 |
|
Other ownership interests in VIE(a) | 588 |
| | 30 |
| | 618 |
|
Registrants’ maximum exposure to loss: | | | | |
|
|
Carrying amount of equity method investments | — |
| | 251 |
| | 251 |
|
Contract intangible asset | 8 |
| | — |
| | 8 |
|
Net assets pledged for Zion Station decommissioning(b) | 2 |
| | — |
| | 2 |
|
__________
| |
(a) | These items represent amounts on the unconsolidated VIE balance sheets, not onin 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 onin 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 $39$9 million and $113$39 million as of December 31, 20172018 and December 31, 2016,2017, respectively; offset by payables to ZionSolutions LLC of $37$9 million and $104$37 million as of December 31, 20172018 and December 31, 2016,2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE. |
For each of the unconsolidated VIE,VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities.VIEs.
As of December 31, 2018 and 2017, Exelon's and Generation's unconsolidated VIEs consist of:
Energy Purchase and Sale Agreements
Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.
ZionSolutions
Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 — Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning activities under the asset sale agreement are complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s or Generation’s general credit.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Investment in Distributed Energy Companies
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 contributed a total $85 million of equity. 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. Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.
During 2015, a company that is consolidated by Generation as a VIE entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company (see additional details in the Consolidated Variable Interest Entities section above). The equity holders (of which Generation is one) contributed to the distributed energy company a total of $227 million of equity in proportion to their ownership interests. The equity holders provided a parental guarantee of up to $275 million in support of equity contributions to the distributed energy company. As all equity contributions were made as of the first quarter of 2017, there is no further payment obligation under the parental guarantee. 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. Generation is not the primary beneficiary; therefore, the investment is recorded using the equity method.
Both distributed energy companies from the 2015 and 2014 arrangements are considered related parties to Generation.
As of December 31, 2016, ExelonComEd and Generation had the following unconsolidated VIE that is no longer a VIE as of December 31, 2017:
Investment in Energy Generating Facility
As of December 31, 2016, Generation had an equity investment in an energy generating facility. The entity was a VIE because Generation guaranteed the debt of the entity, provided equity support, and provided operating services to the entity. Generation was not the primary beneficiary of the entity because Generation did not have the power to direct the activities that most significantly impacted the VIE’s economic performance. During 2017, Generation sold its equity investment in the entity; therefore, the entity is no longer a VIE as of December 31, 2017.
ComEd, PECO and BGE
The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s, ComEd’s, or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk.
The financing trust of BGE, BGE Capital Trust II, was created for the purpose of issuing mandatorily redeemable trust preferred securities. In the third quarter of 2017, BGE redeemed the securities pursuant to the optional redemption provisions of the Indenture, under which the subordinated debt securities were issued, and dissolved BGE Capital Trust II. Prior to dissolution, the BGE Capital Trust II was not consolidated in Exelon's or BGE's financial statements. BGE concluded it did not have a significant variable interest in BGE Capital Trust II as BGE financed its equity interest in the financing trust through the issuance of subordinated debt and, therefore, had no equity at risk. See Note 13 — Debt and Credit Agreements for additional information.
3. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution and transmission services. The performance obligations associated with these sources of revenue are further discussed below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, the Registrant's have elected to use the right to invoice practical expedient for the contracts within these revenue categories and generally
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.
Competitive Power Sales (Exelon and Generation)
Generation sells power and other energy-related commodities to both wholesale and retail customers across multiple geographic regions through its customer-facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related commodities such as capacity, ZECs, RECs or other ancillary services. Certain performance obligations such as power and capacity are generally delivered over time whereas other performance obligations such as RECs and ZECs are generally delivered at a point in time. In either case, revenues related to all of the performance obligations in such bundled power sale contracts are generally recognized concurrently as the power is generated. Except as noted in the paragraph below, there are no significant judgments in allocating the transaction price since all performance obligations are satisfied simultaneously upon the generation of power. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following delivery to the customer and there are generally no significant financing components.
Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, the Registrants estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
Competitive Natural Gas Sales (Exelon and Generation)
Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are recognized over time as the natural gas is delivered to and consumed by the customer. Payment from customers is typically due within the month following delivery of the natural gas to the customer and there are generally no significant financing components.
Other Competitive Products and Services (Exelon and Generation)
Generation also sells other energy-related products and services such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to commercial and industrial customers. These contracts generally contain a single performance obligation, which is the construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. Payments from customers are typically due within 30 or 45 days from the date the invoice is generated and sent to the customer.
Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)
The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and gas distribution services to residential, commercial, and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with these tariff sale contracts is the delivery of electricity and/or natural gas. Tariff sales are generally considered daily contracts given that customers can discontinue service at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally require that customers pay for the services within the month following delivery of the electricity or natural gas to the customer and there are generally no significant financing components or variable consideration.
Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Regulated Transmission Services (Exelon and the Utility Registrants)
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants are members of PJM, the regional transmission organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest. In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii) scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility Registrants utilize output methods to measure the progress towards their completion. Passage of time is used for NITS and access to the wholesale grid and MWhs of energy transported over the wholesale grid is used for scheduling, system control and dispatch services. PJM pays the Utility Registrants for these services on a weekly basis and there are no financing components or variable consideration.
Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)
3.Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs primarily relate to retail broker fees and sales commissions. Generation has capitalized such contract acquisition costs in the amount of $32 million and $26 million as of December 31, 2018 and December 31, 2017, respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These costs are capitalized when incurred and amortized using the straight-line method over the average length of such retail contracts, which is approximately 2 years. Exelon and Generation recognized amortization expense associated with these costs in the amount of $22 million and $30 million for the twelve months endedDecember 31, 2018, and December 31, 2017, respectively, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts with customers that are not already capitalized under existing guidance. In addition, the Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Contract Assets
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 31, 2018:
|
| | | | |
Contract Assets | | Exelon and Generation |
Balance as of January 1, 2018 | | $ | 283 |
|
Increases as a result of changes in the estimate of the stage of completion | | 50 |
|
Amounts reclassified to receivables | | (146 | ) |
Balance at December 31, 2018 | | $ | 187 |
|
The Utility Registrants do not have any contract assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Contract Liabilities
Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a rollforward of the contract liabilities reflected in Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to December 31, 2018:
|
| | | | | | | |
Contract Liabilities | Exelon | | Generation |
Balance as of January 1, 2018 | $ | 35 |
| | $ | 35 |
|
Increases as a result of additional cash received or due | 179 |
| | 465 |
|
Amounts recognized into revenues | (187 | ) | | (458 | ) |
Balance at December 31, 2018 | $ | 27 |
| | $ | 42 |
|
The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 31, 2018 and December 31, 2017, the Utility Registrants' contract liabilities were immaterial.
Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2018. Generation has elected the exemption which permits the exclusion from this disclosure of certain variable contract consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or variable pricing. Thus, this disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
The majority of the Utility Registrants’ tariff sale contracts are generally day-to-day contracts and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to remaining performance obligations for contracts with an original expected duration of one year or less. As such, gas and electric tariff sales contracts and transmission revenue contracts are excluded from this disclosure.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| 2019 | | 2020 | | 2021 | | 2022 | | 2023 and thereafter | | Total |
Exelon | $ | 631 |
| | $ | 329 |
| | $ | 119 |
| | $ | 47 |
| | $ | 138 |
| | $ | 1,264 |
|
Generation | 631 |
| | 329 |
| | 119 |
| | 47 |
| | 138 |
| | 1,264 |
|
Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 24 — Segment Information for the presentation of the Registrant's revenue disaggregation.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
4. Regulatory Matters (All Registrants)
The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.
IllinoisUtility Regulatory Matters
Tax Cuts and Jobs Act (Exelon and ComEd). On January 18,the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2018.
Completed Distribution Base Rate Case Proceedings
|
| | | | | | | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase (Decrease) | | Approved Revenue Requirement Increase (Decrease) | | Approved ROE | Approval Date | Rate Effective Date |
ComEd - Illinois (Electric)(b) | April 16, 2018 | $ | (23 | ) | (a) | $ | (24 | ) | (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
PECO - Pennsylvania (Electric)(c) | March 29, 2018 | $ | 82 |
| (a) | $ | 25 |
| (a) | N/A | December 20, 2018 | January 1, 2019 |
BGE - Maryland (Natural Gas) | June 8, 2018 (amended August 24, 2018 and October 12, 2018) | $ | 61 |
| | $ | 43 |
| | 9.8 | % | January 4, 2019 | January 4, 2019 |
Pepco - Maryland (Electric) | January 2, 2018 (amended February 5, 2018) | $ | 3 |
| (a) | $ | (15 | ) | (a) | 9.5 | % | May 31, 2018 | June 1, 2018 |
Pepco - District of Columbia (Electric)(d) | December 19, 2017 (amended February 9, 2018) | $ | 66 |
| | $ | (24 | ) | (a) | 9.525 | % | August 9, 2018 | August 13, 2018 |
DPL - Maryland (Electric)(e) | July 14, 2017 (amended November 16, 2017) | $ | 19 |
| | $ | 13 |
| | 9.5 | % | February 9, 2018 | February 9, 2018 |
DPL - Delaware (Electric) | August 17, 2017 (amended February 9, 2018) | $ | 12 |
| (a) | $ | (7 | ) | (a) | 9.7 | % | August 21, 2018 | March 17, 2018 |
DPL - Delaware (Natural Gas) | August 17, 2017 (amended February 9, 2018) | $ | 4 |
| (a) | $ | (4 | ) | (a) | 9.7 | % | November 8, 2018 | March 17, 2018 |
__________
| |
(a) | Includes the annual ongoing TCJA tax savings further discussed below. |
| |
(b) | Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the ICC approved ComEd's petition filed on January 5,initial year revenue requirement for 2018 seeking approvaland an increase of $34 million related to pass back to customers beginning February 1, 2018 $201 million in tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates.annual reconciliation for 2017. The amounts being passed back to customers reflect the benefit of lower income tax rates beginning January 1,revenue requirement for 2018 and the settlementannual reconciliation for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.
During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a portionresult of deferred income taxthis revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory liabilities established upon enactmentasset in the first quarter of 2017.
| |
(c) | The PECO base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE. |
| |
(d) | On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018. |
| |
(e) | The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. |
In the second quarter of 2018, DPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amount of the TCJA. Refer$13 million revenue increase agreed to Note 14 - Income Taxes for more detailby the parties in the recent settlement. On September 5, 2018, the MDPSC approved DPL’s proposed revisions to resolve the rate design issue on Corporate Tax Reform.a prospective basis, effective September 5, 2018.
Pending Distribution Base Rate Case Proceedings
|
| | | | | | | | |
Registrant/Jurisdiction | Filing Date | Requested Revenue Requirement Increase |
| Requested ROE | Expected Approval Timing |
ACE - New Jersey (Electric) | August 21, 2018 (amended November 19, 2018) | $ | 122 |
| (a) | 10.1 | % | Third quarter of 2019(b) |
Pepco - Maryland (Electric) | January 15, 2019 | $ | 30 |
| | 10.3 | % | Third quarter of 2019 |
__________
| |
(a) | Requested increase is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the annual ongoing TCJA tax savings further discussed below. |
| |
(b) | ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation. |
Transmission Formula Rates
Electric DistributionTransmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ComEd)ACE).ComEd’s, electric distributionBGE’s, Pepco's, DPL's and ACE's transmission rates are each established throughbased on a performance-based formula rate.FERC-approved formula. ComEd, isBGE, Pepco, DPL and ACE are required to file an annual update to the performance-basedFERC-approved formula rate on or before May 1,15, with the resulting rates effective in Januaryon June 1 of the followingsame year. ThisThe annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect forbeginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). Throughout each year, ComEd records 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 best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. The regulatory asset associated with electric distribution formula rate is amortized to Operating revenues in ComEd's Consolidated Statement of Operations and Comprehensive Income as the associated amounts are recovered through rates. Changes to the distribution formula rate as a result of FEJA are discussed below.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For each of the following years, the ICC approved2018, the following total increases/(decreases) were included in ComEd'sComEd’s, BGE’s, Pepco's, DPL's and ACE's electric distributionstransmission formula rate filings:
|
| | | | | | | | | | | | |
Annual Electric Distribution Filings | 2017 |
| 2016 |
| 2015 | |
ComEd's requested total revenue requirement increase (decrease) | $ | 96 |
| | $ | 138 |
| | $ | (50 | ) | |
| | | | | | |
Final ICC Order | | | | | | |
Initial revenue requirement increase | $ | 78 |
| | $ | 134 |
| | $ | 85 |
| |
Annual reconciliation increase (decrease) | 18 |
| | (7 | ) | | (152 | ) | |
Total revenue requirement increase (decrease) | $ | 96 |
| | $ | 127 |
| (a) | $ | (67 | ) | |
| | | | | | |
Allowed Return on Rate Base: | | | | | | |
Initial revenue requirement | 6.47 | % | | 6.71 | % | | 7.05 | % | |
Annual reconciliation | 6.45 | % | | 6.69 | % | | 7.02 | % | |
Allowed ROE: | | | | | | |
Initial revenue requirement | 8.40 | % | | 8.64 | % | | 9.14 | % | |
Annual reconciliation | 8.34 | % | (b) | 8.59 | % | (b) | 9.09 | % | (b) |
| | | | | | |
Effective date of rates | January 2018 |
| | January 2017 |
| | January 2016 |
| |
|
| | | | | | | | | | | | | | |
Registrant | Initial Revenue Requirement (Decrease) Increase(b) | Annual Reconciliation Increase/(Decrease) | Total Revenue Requirement (Decrease) Increase |
| Allowed Return on Rate Base(d) | Allowed ROE(e) |
ComEd(a) | $ | (44 | ) | $ | 18 |
| $ | (26 | ) |
| 8.32 | % | 11.50 | % |
BGE(a) | 10 |
| 4 |
| 26 |
| (c) | 7.61 | % | 10.50 | % |
Pepco | 6 |
| 2 |
| 8 |
|
| 7.82 | % | 10.50 | % |
DPL | 14 |
| 13 |
| 27 |
|
| 7.29 | % | 10.50 | % |
ACE(a) | 4 |
| (4 | ) | — |
|
| 8.02 | % | 10.50 | % |
__________
| |
(a) | On March 22, 2017,The time period for any formal challenges to the ICC issued an order approving ComEd's proposal to reduce the 2016 revenue requirement by $18 million, which was reflected in customer rates beginning in April 2017. This reduction is not reflected in the 2016 revenue requirement amounts above.annual transmission formula rate update filings expired with no formal challenges submitted. |
| |
(b) | IncludesThe initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion below. |
| |
(c) | The change in BGE's transmission revenue requirement includes a reductionFERC approved dedicated facilities charge of 6 basis points in 2017$12 million to recover the costs of providing transmission service to specifically designated load by BGE. |
| |
(d) | Represents the weighted average debt and 5 basis points in 2016equity return on transmission rate bases. |
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and 2015the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a reliability performance metric penalty.50-basis-point incentive adder for being a member of a RTO. |
Illinois Future EnergyPending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Tax Cuts and Jobs Act (Exelon, Generation
The Utility Registrants have made filings with their state regulatory commissions to pass back tax savings related to TCJA to their distribution customers, which are detailed below. The tax savings include the benefit of lower federal income tax rates and ComEd)
Background
On December 7, 2016, FEJA was signed into law by the Governorsettlement of Illinois. FEJA went into effect on June 1, 2017, and includes, among other provisions, (1) a ZES providing compensationportion of the deferred income tax regulatory liabilities established upon the enactment of the TCJA. The ongoing annual TCJA tax savings in the table below represent the annual savings for certain nuclear-powered generating facilities, (2) an extensiondistribution customers reflected in the initial customers rates approved after the TCJA. Subsequent annual TCJA tax savings will be approved as part of and certain adjustmentsthe annual update to ComEd’sthe electric distribution formula rate (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd (4) revisions to the Illinois RPS requirements, (5) provisionsor base rate case proceedings 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,PECO, BGE, Pepco, DPL 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.
Zero Emission Standard
FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria.ACE.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | |
| Ongoing TCJA Tax Savings | Stub Period Bill Credit from TCJA Tax Savings |
Registrant/Jurisdiction | Amount | Approval Date | Rate Effective Date | Stub Period | Approval Date | Refund Amount/Period |
ComEd - Illinois (Electric) | $ | 201 |
| January 18, 2018 | February 1, 2018 | Not applicable |
PECO - Pennsylvania (Electric) | $ | 71 |
| December 20, 2018 | January 1, 2019 | January 1, 2018 - December 31, 2018 | December 20, 2018 | $67 / 2019 (majority in January) |
PECO - Pennsylvania (Natural Gas) | $ | 4 |
| (a) | July 1, 2018 | Not applicable |
BGE - Maryland (Electric) | $ | 72 |
| January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018
| To be addressed in next electric distribution base rate case |
BGE - Maryland (Natural Gas) | $ | 31 |
| January 31, 2018 | February 1, 2018 | January 1, 2018 - January 31, 2018
| January 4, 2019 | $2 / Q1 2019 |
Pepco - Maryland (Electric) | $ | 31 |
| May 31, 2018 | June 1, 2018 | January 1, 2018 - June 1, 2018 | May 31, 2018 |
$10 / July 2018 |
Pepco - District of Columbia (Electric) | $ | 39 |
| August 9, 2018 | August 13, 2018 | January 1, 2018 - August 12, 2018
| September 7, 2018 | $20 / September 2018 |
DPL - Maryland (Electric) | $ | 14 |
| April 18, 2018 | April 20, 2018 | January 1, 2018 - March 31, 2018
| April 18, 2018 | $2 / June 2018 |
DPL - Delaware (Electric) | $ | 19 |
| August 21, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018
| August 21, 2018 | $3 / Q4 2018 |
DPL - Delaware (Natural Gas) | $ | 7 |
| November 8, 2018 | March 17, 2018 | February 1, 2018 - March 17, 2018
| November 8, 2018 | $1 / Q4 2018 |
ACE - New Jersey (Electric) | $ | 23 |
| August 29, 2018 | September 8, 2018 | January 1, 2018 - June 30, 2018
| August 29, 2018 | $6 / Q4 2018
|
__________
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(a) | On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers. |
As discussed above, ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. On September 11, 2017, the ICC approved the IPA's ZES Procurement PlanDecember 13, 2016 (as amended on March 13, 2017) and on February 23, 2018 (as amended on July 9, 2018), BGE and ComEd, Pepco, DPL and ACE, respectively, each filed with the ICC on July 31, 2017. Bidders interested in participating in the procurement process had 14 days following the ICC's approvalFERC to revise their transmission formula rate mechanisms to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets, including those established upon enactment of the plan to submit the required eligibility information and become qualified bidders. Generation’s Clinton and Quad Cities nuclear plants timely submitted the required eligibility information to the ICC and responded to follow up questions. Winning bidders will contract directly with Illinois utilities, including ComEd, for 10-year terms extending through May 31, 2027. 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 annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities will be required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, the ZEC annual cost cap is set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap will be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year.
ComEd recovers all costs associated with purchasing ZECs through a rate rider that provides for an annual reconciliation and true-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 with interest. ComEd began billing its retail customers under its new ZEC rate rider on June 1, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. 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 PJM's FERC-approved 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. In addition, on March 31, 2017, plaintiffs in both lawsuits filed motions for preliminary injunction with the court; the court stayed briefing on the motions for preliminary injunction until the resolution of the motions to dismiss.On July 14, 2017, the district court granted the motions to dismiss. On July 17, 2017, the plaintiffs appealed the decision to the Seventh Circuit. Briefs were fully submitted on December 12, 2017, the Court heard oral argument on January 3, 2018. At the argument, the Court asked for supplemental briefing, which was filed on January 26, 2018. 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, cash flows and financial positions.
TCJA. See Note 8 — Early Nuclear Plant Retirementsdiscussion below for additional information regarding the economic challenges facing Generation’s Clinton and Quad Cities nuclear plants and the expected benefits of the ZES.these filings.
ComEd Electric Distribution Rates
FEJA extended the sunset dateSee Note 14 - Income Taxes for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allowed ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allowed ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd revised its electric distribution formula rate to eliminate the ROE collar, which eliminates any unfavorable or favorable impacts of weather or load from ComEd’s electric distribution formula rate revenues 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 ComEd's electric distribution formula rate 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 in the first quarteradditional information on Corporate Tax Reform.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2017. As of December 31, 2017, ComEd recorded an increase to its electric distribution services costs regulatory asset of approximately $32 million for this change.Other State Regulatory Matters
FEJA requires ComEd to make non-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.Illinois Regulatory Matters
Energy Efficiency
Prior to FEJA, Illinois law required ComEd to implement cost-effective energy efficiency measures Formula Rate (Exelon and for a 10-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 $350 million to $400 million annually 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. On September 11, 2017, the ICC approved ComEd's 2018-2021 energy efficiency plan with minor modifications filed by ComEd with the ICC on June 30, 2017.
As allowed by FEJA, ComEd cancelled its existing energy efficiency rate rider effective June 2, 2017. On August 1, 2017, ComEd filed with the ICC a reconciliation of revenues and costs incurred through the cancellation date. On August 30, 2017, the ICC approved ComEd's request, filed on August 1, 2017, to issue an $80 million credit on retail customers' bills in October 2017 for the majority of the over-recoveries with any final adjustment applicable to the over-recoveries to be billed or credited in the future. As of December 31, 2017, ComEd’s over-recoveries associated with its former energy efficiency rate rider were $4 million and are expected to be refunded to customers in future rates.
ComEd).FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on 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 is required to file an update to its energy efficiency formula rate on or before June 1st each year, with resulting rates effective in January of the following year. The annual update will beis based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes.taxes (initial year revenue requirement). The update will also include a reconciliation ofreconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the revenue requirement based on actual prior year costs and actual year-end energy efficiency regulatory asset balances less any related deferred income taxes. ComEd records a regulatory asset or liability and corresponding increase or decrease to
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 reconciliation.
On August 15, 2017, the ICC approved ComEd's new initial energy efficiency formula rate filed pursuant to FEJA. The order establishes the formula under which energy efficiency rates will be calculated going forward and the revenue requirement used to set the initial rates for the period October 1, 2017 through December 31, 2017. The initial revenue requirement is based on projected costs and projected PJM capacity revenues for the period from June 1, 2017 through December 31, 2017, and projected year-end 2017 energy efficiency regulatory asset balances (less related deferred income taxes)(annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to effectively offset the favorable or unfavorable impacts to ComEd's energy efficiency formula rate revenues associated with variationsthose in delivery volumes associated with above or below normal weather, numbers of customers or usage per customer.
On September 11, 2017, the ICC approved ComEd's annual energy efficiencyComEd’s electric distribution formula rate. The order establishes the revenue requirement used to set rates that will take effect in January 2018. The revenue requirement for
During 2018, is based on projected 2018 energy efficiency costs and PJM capacity revenues, and year-end 2018 energy efficiency regulatory asset balances (less related deferred income taxes).
For each of the following years, the ICC approved the following total increases/(decreases)increases in ComEd's requested energy efficiency revenue requirement:
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Annual Energy Efficiency Filings | Initial | | 2017 |
ComEd's requested total revenue requirement (decrease) increase | $ | (7 | ) | (a) | $ | 12 |
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| | | |
Allowed Return on Rate Base: | | | |
Initial revenue requirement | 6.47 | % | | 6.47 | % |
Allowed ROE: | | | |
Initial revenue requirement | 8.40 | % | | 8.40 | % |
| | | |
Effective date of rates (b) | October 2017 |
| | January 2018 |
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| | | | | | | | | | | |
Filing Date | Requested Revenue Requirement Increase | Approved Revenue Requirement Increase | | Approved ROE | Approval Date | Rate Effective Date |
June 1, 2018 | $ | 39 |
| $ | 42 |
| (a) | 8.69 | % | December 4, 2018 | January 1, 2019 |
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(a) | Reflects higher projected PJM capacity revenues comparedComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1 million related to projected energy efficiency costs. |
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(b) | An ICC order on the annual reconciliation of any differences between thefor 2017. The revenue requirement in effectfor 2018 and 2019 and the revenue requirement based on actual costsannual reconciliation for 2017 provides for a weighted average debt and 2018 is expected in December 2018 and December 2019, respectively.equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate. |
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 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 for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. FEJA also requires ComEd to use RPS collections to fund utility job training and workforce development programs in the amounts of $10 million in each of the years 2017, 2021, and 2025. ComEd recorded a $20 million noncurrent liability as of December 31, 2017 associated with this obligation. ComEd will recover all costs associated with purchasing RECs and funding utility job training and workforce development programs through a new RPS rate rider that provides for a reconciliation and true-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 with
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
interest. The first reconciliation and true-up for RECs will occur in 2021 and 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 and true-up. ComEd began billing its retail customers under its new RPS rate rider on June 1, 2017 and recorded a related regulatory liability of $21 million as of December 31, 2017. ComEd also recorded a regulatory liability of $41 million for alternative compliance payments received from RES to purchase RECs on behalf of the RES in the future.
As of December 31, 2017, ComEd had received $62 million of over-recovered RPS costs and alternative compliance payments from RES, which are deposited into a separate interest-bearing bank account pursuant to FEJA. The current portion is classified as Restricted cash and the non-current portion is classified as other deferred debits on Exelon's and ComEd's Balance Sheets.
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.
On June 30, 2017, ComEd submitted a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW. Such projections indicate that customer rate impacts will not exceed the limitations set by FEJA discussed below. 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 rolling 10-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 the 10-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 for low-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.
Renewable Energy Resources (Exelon and ComEd). In accordance with FEJA, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA filed its long term renewable
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
resource procurement plan (LT Plan) with the ICC on December 4, 2017. The LT Plan requires a certain percentage of electricity sales be met with a climbing percentage of REC procurement. The 2017 delivery year requirement was 13%, with the obligation increasing by at least 1.5% each year thereafter to at least 25% by the 2025 delivery year; and continuing at no less than 25% for each delivery year thereafter.
Each RES and each Illinois utility, which includes ComEd, is responsible for the renewable resource obligation for the customers to which it supplies power. Over time, this will change and ComEd 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 ComEd for the retail load it supplies and for 50% of the retail customer load supplied by RES in ComEd's service territory on February 28, 2017. ComEd's procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019. All goals are subject to rate impact criteria set forth by Illinois legislation. As of December 31, 2017, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.
Pennsylvania Regulatory Matters
Tax Cuts and Jobs Act (Exelon and PECO). PECO is working with the PAPUC and stakeholders on behalf of its distribution customers to determine the proper regulatory mechanisms and timing to reflect the tax benefits from the TCJA.
2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUC requesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10, 2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution service revenue. No overall ROE was specified in the settlement. On December 17, 2015, the PAPUC approved the settlement of PECO’s electric distribution rate case, which included the approval of the In-Program Arrearage Forgiveness ("IPAF") Program. The approved electric delivery rates became effective on January 1, 2016.
The IPAF Program provides for forgiveness of a portion of the eligible arrearage balance of its low-income Customer Assistance Program (CAP) accounts receivable at program inception. The forgiveness will be granted to the extent CAP customers remain current over the duration of the five-year payment agreement term. The Settlement guarantees PECO’s recovery of two-thirds of the arrearage balance through a combination of customer payments and rate recovery, including through future rates cases if necessary. The remaining one-third of the arrearage balance has been absorbed by PECO through bad debt expense on its Consolidated Statements of Operations. In October 2016, the IPAF was fully implemented. PECO recorded a regulatory asset representing previously incurred bad debt expense associated with the eligible accounts receivable balances, which is included in the Regulatory assets table below.
Maryland Regulatory Matters
Tax Cuts and Jobs Act (Exelon, BGE, PHI, Pepco and DPL). On January 12, 2018, the MDPSC issued an order that directed each of BGE, Pepco and DPL to track the impacts of the TCJA beginning January 1, 2018 and file by February 15, 2018 how and when they expect to pass through such impacts to their customers.
On January 31, 2018, the MDPSC approved BGE’s petition to pass back to customers beginning February 1, 2018 $103 million in tax savings resulting from the enactment of the TCJA through a reduction in distribution rates, of which $72 million and $31 million were related to electric and natural gas, respectively. On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
case to reflect $31 million in TCJA tax savings. By mid-February 2018, DPL is planning to file with the MDPSC seeking approval to pass back to customers beginning in 2018 $13 million in TCJA tax savings through a reduction in electric distribution rates. The amounts being passed back or proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. Refer to Note 14 — Income Taxes for more detail on Corporate Tax Reform.
After the filings due by February 15, 2018, it is expected that the MDPSC will address the treatment of the TCJA tax savings tracked by BGE, Pepco and DPL for the period January 1, 2018 through the effective date of their respective $103 million, $31 million and $13 million customer rate adjustments described above.
2018 Maryland Electric Distribution Rates (Exelon, PHI and Pepco). On January 2, 2018, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $41 million, reflecting a requested ROE of 10.1%. On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect $31 million in TCJA tax savings, thereby reducing the requested annual base rate increase to $11 million. Pepco expects a decision in the matter in the third quarter of 2018, but cannot predict how much of the requested increase the MDPSC will approve.
2017 Maryland Electric Distribution Rates (Exelon, PHI and Pepco). On March 24, 2017, Pepco filed an application with the MDPSC to increase its annual electric distribution base rates by $69 million, which was updated to $67 million on August 24, 2017, reflecting a requested ROE of 10.1%. The application included a request for an income tax adjustment to reflect full normalization of removal costs associated with pre-1981 property, which accounted for $18 million of the requested increase. On October 20, 2017, the MDPSC approved an increase in Pepco electric distribution rates of $34 million, reflecting a ROE of 9.5%. On October 27, 2017, the MDPSC issued an errata order revising the approved increase in Pepco electric distribution rates to $32 million. The errata order corrected a number of computational errors in the original order but did not alter any of the findings. The new rates became effective for services rendered on or after October 20, 2017. In its decision, the MDPSC denied Pepco’s request regarding the income tax adjustment without prejudice to Pepco filing another similar proposal with additional information. On November 20, 2017, an interested party in the proceeding filed a request for rehearing. On December 4, 2017, Pepco filed its response in opposition to the request for rehearing. Pepco cannot predict the outcome of this matter or when it will be decided.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco). On November 15, 2016, the MDPSC approved an increase in electric distribution base rates of $53 million based on a ROE of 9.55%. The new rates became effective for services rendered on or after November 15, 2016. MDPSC also approved Pepco's recovery of substantially all of its capital investment and regulatory assets associated with its AMI program as part of the newly effective rates as well as a recovery over a five-year period of transition costs related to a new billing system implemented in 2015. As a result, during the fourth quarter of 2016, Exelon, PHI and Pepco established a regulatory asset of $13 million, wrote-off $3 million in disallowed AMI costs and recorded a pre-tax credit to net income for $10 million. Additionally, the MDPSC denied Pepco's request to extend its Grid Resiliency Program surcharge for new system reliability and safety improvement projects, with costs for such programs to be recovered going forward through base rates.
2017 Maryland Electric Distribution Rates (Exelon, PHI and DPL). On July 14, 2017, DPL filed an application with the MDPSC to increase its annual electric distribution base rates by $27 million, which was updated to $19 million on November 16, 2017, reflecting a requested ROE of 10.1%. On December 18, 2017, a settlement agreement was filed with the MDPSC wherein DPL will be granted a rate increase of $13 million, and a ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs. On January 5, 2018, the MDPSC held a hearing on the settlement agreement.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL expects a decision in the matter in the first quarter of 2018, but cannot predict whether the MDPSC will approve the settlement agreement as filed or how much of the requested increase will be approved.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On February 15, 2017, the MDPSC approved an increase in DPL electric distribution rates of $38 million reflecting 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 $5 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.
2015 Maryland Electric and Natural Gas Distribution Base Rates (Exelon and BGE). On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas distribution 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. On November 15, 2016, Baltimore County Circuit Court issued an order deciding that the cases should be consolidated and should proceed in Baltimore County Circuit Court. However, on January 9, 2017, BGE filed to withdraw its appeal of the MDPSC's orders and on January 10, 2017, the residential consumer advocate filed to withdraw its appeal as well. Refer to the Smart Meter and Smart Grid Investments disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE. See Conduit Lease with City of Baltimore in Litigation and Regulatory Matters of Note 23 - Commitments and Contingencies for information about the settlement agreement related to BGE's use of the City-owned underground conduit system.
Cash Working Capital Order (Exelon and BGE).On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its 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 its SOS-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 actacts as a proxy for retail suppliers’ costs. The Commission accepted BGE's
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016,Subsequently, the MDPSC Staff requestedand residential consumer advocate sought clarification concerningand appealed the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing. On February 22, 2017, the residential consumer advocate filed anSOS. The appeal of the MDPSC's orderscurrently resides with the Circuit Court for Baltimore City. The residential consumer advocate filed its Memorandum on Appeal on June 5, 2017 and subsequent Reply Memoranda were filed by BGE and the MDPSC on July 7, 2017 and July 12, 2017, respectively. On August 7, 2017, following oral argument by the parties, a decision was issued from the Circuit Court affirming the decision of the MDPSC. On September 5, 2017, the residential consumer advocate filed an appeal of the Circuit Court's decision to the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. Refer toSee AMI programs in the Regulatory Assets and Liabilities section below for further details.additional information.
As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficialcost-
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 3rd order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. On June 30, 2016, BGE and the residential consumer advocate subsequently both 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. The residential consumer advocate also subsequently filed for a petition for rehearing of the June 3rd order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative.
As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution base rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of non-AMI plantlegacy meter costs from Property, plant and equipment, net to Regulatory assets onin Exelon's and BGE's Consolidated Balance Sheets. In BGE’s 2018 natural gas distribution base rate case, the MDPSC allowed BGE to recover the gas portion of the post-test year regulatory asset, including a return thereon, over three years. The electric portion of the same regulatory asset will be addressed in BGE’s next electric distribution base rate case.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation intended to accelerate gas infrastructure replacements in Maryland was signed into law. The law establishedto establish a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
into gas distribution base rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.
On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On July 1, 2016, BGE filed an amendment to its infrastructure replacement plan, which the MDPSC conditionally approved in an order dated November 23, 2016. The revised surcharge reflecting the costs of the amendment became effective January 1, 2017. On November 1, 2017, BGE filed a surcharge update to be effective January 1, 2018 along with its 2018 project list and projected capital estimates of $136 million to be included in the 2018 surcharge calculation. The MDPSC subsequently approved BGE's 2018 project list and the proposed surcharge for 2018. As of December 31, 2017, BGE recorded a regulatory liability of less than $1 million, representing the difference between the surcharge revenues and program costs.
On December 1, 2017 (and as(as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $963$732 million, with an associated revenue requirement of $242$200 million. BGE expects a decision in the matter by May 31, 2018, but cannot predict whether the MDPSC will approve the plan as filed.
Delaware Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and DPL). On January 16, 2018, the DPSC opened a docket to examine the impacts of the TCJA on the cost of service and rates of all regulated public utilities in Delaware, which includes DPL. The DPSC also stated the TCJA benefits would be addressed in DPL's pending rate case.
In response, by mid-February 2018, DPL is planning to file with the DPSC updates to its electric and gas distribution rate cases described below to reflect approximately $26 million in tax savings resulting from the enactment of the TCJA, of which $19 million and $7 million are related to electric and natural gas, respectively. The updated requests for amounts being passed back to customers would reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. Refer to Note 14 - Income Taxes for more detail on Corporate Tax Reform. DPL expects a decision in the matter in the third quarter of 2018 for the electric distribution proceeding and in the fourth quarter of 2018 for the gas distribution proceeding, but cannot predict how much of the requested increase the DPSC will approve. It is expected that the DPSC will address in a future rate proceeding DPL's treatment of the TCJA tax savings for the period February 1, 2018 through the effective date of any customer rate adjustments in the pending rate proceedings.
2017 Delaware Electric and Natural Gas Distribution Rates (Exelon, PHI and DPL). On August 17, 2017, DPL filed applications with the DPSC to increase its annual electric and natural gas distribution base rates by $24 million and $13 million respectively, reflecting a requested ROE of 10.1%. DPL filed updated testimony on October 18, 2017, to request a $31 million increase in electric distribution rates, and updated testimony on November 7, 2017, to request an $11 million increase in natural gas distribution rates. While the DPSC is not required to issue a decision on the applications within a specified period of time, Delaware law allows DPL to put into effect $2.5 million of the rate increases for both electric and natural gas two months after filing the application and the entire requested rate increases seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. On October 24, 2017, the Staff of the DPSC and the Public Advocate filed a joint motion to dismiss DPL's electric distribution base rate application without prejudice to refiling, arguing that the amount of the requested increase to $31 million required additional time to review and additional public notice. In November 2017, the DPSC denied the joint motion to dismiss.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2016 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed applications 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, reflecting a requested ROE of 10.6%. Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases effective July 16, 2016. On December 17, 2016, the DPSC approved that an additional $30 million in electric distribution rates and an additional $10 million in gas distribution rates effective December 17, 2016, subject to refund based on the final DPSC orders.
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 annual electric distribution base rates of $31.5 million reflecting a ROE of 9.7% compared to the $32 million increase previously put into effect. On May 23, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective June 1, 2017. Pursuant to the settlement agreement, no refund of the interim rates put into effect on July 16, 2016 and December 17, 2016 (as discussed above) is required.
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 annual natural gas distribution base rates of $4.9 million reflecting a ROE of 9.7%. The settlement agreement also provides that DPL will refund amounts collected under the temporary rates effective July 16, 2016 and December 17, 2016 (as discussed above) in excess of the $4.9 million, and that the new rates will be effective within thirty days of DPSC approval of the settlement agreement. On June 6, 2017, the DPSC issued an order approving the settlement agreement, with the new rates effective July 1, 2017. Pursuant to the settlement agreement, a rate refund plus interest of approximately $5 million was issued to customers beginning in August 2017. This was a one-time refund and was included on customer bills from mid-August through mid-September.
District of Columbia Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and Pepco). On January 23, 2018, the DCPSC opened a rate proceeding directing Pepco to track the impacts of the TCJA beginning January 1, 2018 and file its plan to reduce the current revenue requirement by customer class by February 12, 2018. The DCPSC stated it will address the impact of the TCJA on future rates within Pepco's pending electric distribution rate case discussed below and Pepco will accordingly update its current distribution rate case in February 2018.
Separately, on February 6, 2018, Pepco filed with the DCPSC seeking approval to pass back to customers beginning in 2018 $39 million in tax savings resulting from the enactment of the TCJA through a reduction in electric distribution rates. The amounts being passed back to customers would reflect the annual benefit of lower income tax rates and the settlement of a portion of deferred income tax regulatory liabilities established upon enactment of the TCJA. It is expected that the DCPSC will address in a future rate proceeding Pepco's treatment of the TCJA tax savings for the period January 1, 2018 through the effective date of any customer rate adjustments. Refer to Note 14 - Income Taxes for more detail on Corporate Tax Reform.
2017 District of Columbia Electric Distribution Base Rates (Exelon, PHI and Pepco). On December 19, 2017, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $66 million, reflecting a requested ROE of 10.1%. By mid-February, Pepco will update its current distribution rate case to reflect the TCJA impacts from January 1, 2018 through the effective date of the $39 million customer rate adjustment described above. Pepco expects a decision in the matter in the fourth quarter of 2018, but cannot predict how much of the requested increase the DCPSC will approve.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2016 District of Columbia 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 $77 million on February 1, 2017, reflecting a requested ROE of 10.6%.
On July 25, 2017, the DCPSC approved an increase in Pepco electric distribution base rates of $37 million reflecting a ROE of 9.5%. The new rates became effective for services rendered on or after August 15, 2017. In its decision, the DCPSC ordered that the $26 million customer rate credit created as a result of the Exelon and PHI merger will be provided primarily to residential customers and some small commercial customers to offset the impact of this increase until that amount has been exhausted, which is expected to take approximately two years. Additionally, the Commission is holding approximately $6 million to $7 million of the customer rate credit for use toward a possible new class of customers for certain senior citizens and disabled persons. The DCPSC also held that Pepco's bill stabilization adjustment, which decouples distribution revenues from utility customers from the amount of electricity delivered, will continue to be in place and that no refund of previously collected funds is required. Several parties filed requests that the DCPSC reconsider the order on various issues, and on October 6, 2017, the Commission issued an order denying each of the requests.
District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco).The District of Columbia government enacted on an emergency basis (effective May 17, 2017) and thereafter on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia.
The $250 million of project costs funded by Pepco will earn a return and be recovered through a volumetric surcharge on the electric bill of substantially all of Pepco's customers in the District of Columbia. Pepco will earn a return on these project costs.
The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of all the assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion.completion, and Pepco will not recover or earn a return on the cost of the assets transferred to it by the District of Columbia.these assets.
In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year plan in the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. After the initial application, Pepco will then be required to make two additional applications. On November 9, 2017, the DCPSC issued an order approving the First Biennial Plan and the application for a financing order. Pursuant to that order, Pepco is obligated to pay $187.5 million to the District of Columbia over the six-year project term, of which it expects to pay $27.5$30 million in 2018.2019. Pepco recorded an obligation and offsetting regulatory asset in November. On December 11, 2017, an interested party filed for reconsideration of the DCPSC's November 9 order and on January 18, 2018, the DCPSC denied the interested party’s request. Rates for the DC PLUG initiative went into effect on February 7, 2018.
New Jersey Regulatory Matters
Tax Cuts and Jobs Act (Exelon, PHI and ACE). On January 31, 2018, the NJBPU issued an order mandating that New Jersey utility companies, including ACE, pass any economic benefit from the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
TCJA to rate payers. The order directed an obligation and offsetting regulatory asset in November. Rates for the DC PLUG initiative went into effect on February 7, 2018.
New Jersey utility companies to file by March 2,Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, proposed tariff sheets reflecting TCJA benefits, with new rates to be implemented effective April 1, 2018. In addition, the NJBPU directed New Jersey utility companies to file by March 2, 2018 a PetitionACE filed with the NJBPU outlining how they proposethe company’s Infrastructure Investment Program (IIP) proposing to refund any over-collection associated with revised rates not being in place from January 1, 2018 through March 31, 2018, with interest.
ACE estimates that approximately $23 million in TCJA savings will be passed back to ACE customers, reflecting the annual benefit of lower income tax rates and the settlementseek recovery of a portionseries of deferred income tax regulatory liabilities established upon enactment of the TCJA. Referinvestments through a new rider mechanism, totaling $338 million, between 2019-2022 to Note 14 - Income Taxesprovide safe and reliable service for its customers. The IIP will allow for more detail on Corporate Tax Reform.timely recovery of investments made to modernize and enhance ACE’s electric system. ACE currently expects a decision in this matter in the second quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.
New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE).The Consolidated Tax Adjustment (CTA) is a New Jersey ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. In 2013, the NJBPU openedAfter opening a generic proceeding to review the policy. Inpolicy, in 2014, the NJBPU issued a decision which retained the CTA, but in a highly modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. No party filed an appeal of the Court’s decision, and theThe NJBPU has issued a proposed rule for comment, consistent with the requirements of the Administrative Procedures Act. The substance ofOn January 17, 2019, the NJBPU adopted the proposed rule is consistent with the NJBPU’s decision in the generic proceeding. If the NJBPU were to apply the CTA in its unmodified form, it couldregulations, which do not have a material prospective impact on ACE. The CTA regulations will be sent to ACE through a reductionthe Office of Administrative Law for publication in rate base in future rate cases.the New Jersey Register, which is expected on or before March 4, 2019.
2017 New Jersey Electric Distribution RatesClean Energy Legislation (Exelon PHI and ACE).On March 30, 2017, ACE filed an application withMay 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021; lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual electricusage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution rates by $70 million (beforesystem; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property which the NJBPU issued regulations on January 17, 2019.
On the same day, the Governor of New Jersey salesalso signed new legislation, effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and use tax), which was updatedthat their revenues are insufficient to $73 million on July 14, 2017, reflectingcover their costs and risks. Electric distribution utilities in New Jersey, including ACE, will be authorized to collect from retail distribution customers through 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 certainnon-bypassable charge all costs associated with reliability and system renewal-related capital investments. the utility’s procurement of the ZECs. See Generation Regulatory Matters below for additional information.
On September 8, 2017, ACE entered into a settlement agreement with the NJBPU staff, the New Jersey Division of Rate Counsel and Wal-Mart Stores, Inc. in its electric distribution rate proceeding, which provides for an increase in ACE annual electric distribution base rates of $43 million (before New Jersey sales and use tax) reflecting a ROE of 9.6%. In addition, pursuant to the settlement agreement, ACE agreed to withdraw its request for approval of a System Renewal Recovery Charge without prejudice to its right to refile. On September 22, 2017, the NJBPU issued an order approving the settlement agreement, with the new rates effective on October 1, 2017.Other Federal Regulatory Matters
2016 New Jersey Electric Distribution Base RatesTransmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On August 24,December 13, 2016 the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff(as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and Unimin Corporation, which, among other things,future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that a determination on ACE's grid resiliency program, PowerAhead, would be separated into a phase II of the rate proceedingamortized and decided at a later date. PowerAhead includes capital investments to enhance the resiliency of the system through improvements focused on improving the distribution system's ability to withstand major storm events. A stipulation of settlement with respect to the PowerAhead program (the PowerAhead Stipulation) was approved by the NJBPU on May 31, 2017. As adopted, the PowerAhead program includes an approved investment level of $79 million to be recovered through the cost recovery mechanism described in the PowerAhead Stipulation. The NJBPU order adopting the PowerAhead Stipulation was effective on June 10, 2017.prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
approval. On November 16, 2017, UpdateFERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. FERC’s rejection order focused on the lack of timeliness of BGE’s request to recover amounts that would have been previously amortized but indicated that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. Based on FERC’s order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and Reconciliationrecovered through rates had the transmission formula rate provided for such recovery was no longer probable of Certain Under-Recovered Balances (Exelon,recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ACE recorded the following charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets. Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s November 16, 2017 FERC order. See above for additional information regarding PECO's transmission formula rate filing.
|
| | | |
| For the year ended December 31, 2017 |
Exelon | $ | 35 |
|
ComEd | 3 |
|
BGE | 5 |
|
PHI | 27 |
|
Pepco | 14 |
|
DPL | 6 |
|
ACE | 7 |
|
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate income tax rate effective January 1, 2018 provided for in the TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets.
On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.
On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, again citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s separate Notice of Inquiry of such amounts issued on March 15, 2018.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted its 2017 annual petitionnew filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. FERC issued deficiency letters requesting additional information on November 21, 2018 and January 28, 2019. ComEd, BGE, Pepco, DPL, and ACE responded to the November 21, 2018 deficiency letter on November 29, 2018 but cannot predict the outcome of these FERC proceedings. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $76 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of December 31, 2018.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit.
PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with the NJBPU seekingFERC to reconcile and update (i)resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs relatedperiods prior to surcharges for the New Jersey Societal Benefit Program (a statewide public interest programJanuary 1, 2016 that is intendedare expected to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts. As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate decrease of approximately $29 million (revised to approximately $32 million in April 2017, based upon an update for actualsbe refunded or recovered through March 2017), including New Jersey sales and use tax. PJM wholesale transmission rates through December 2025.
On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, several parties filed petitions for rehearing or clarification.
Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the second quarter of 2018 and as adjusted in the third quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
|
| | | | | | | | | | | | |
| PJM Receivable | PJM Payable | Regulatory Asset | Regulatory Liability |
Exelon | $ | 220 |
| $ | 176 |
| $ | 136 |
| $ | 221 |
|
Generation(a) | — |
| 41 |
| — |
| — |
|
ComEd | 122 |
| — |
| — |
| 122 |
|
PECO | 85 |
| — |
| — |
| 85 |
|
BGE | — |
| 51 |
| 51 |
| — |
|
PHI | 13 |
| 84 |
| 85 |
| 14 |
|
Pepco | — |
| 84 |
| 84 |
| — |
|
DPL | 10 |
| — |
| — |
| 10 |
|
ACE | 3 |
| — |
| 1 |
| 4 |
|
__________
| |
(a) | Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2018 and December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory assets | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | $ | 2,553 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Pension and other postretirement benefits - Merger related | 1,266 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deferred income taxes | 414 |
| | — |
| | 404 |
| | — |
| | 10 |
| | 10 |
| | — |
| | — |
|
AMI programs - Deployment Costs | 202 |
| | — |
| | — |
| | 113 |
| | 89 |
| | 50 |
| | 39 |
| | — |
|
AMI programs - Legacy Meters | 328 |
| | 136 |
| | 24 |
| | 48 |
| | 120 |
| | 90 |
| | 30 |
| | — |
|
AMI programs - Post-test year costs | 32 |
| | — |
| | — |
| | 32 |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution formula rate annual reconciliations | 158 |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution formula rate significant one-time events | 81 |
| | 81 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy efficiency costs | 472 |
| | 472 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fair value of long-term debt | 702 |
| | — |
| | — |
| | — |
| | 569 |
| | — |
| | — |
| | — |
|
Fair value of PHI's unamortized energy contracts | 561 |
| | — |
| | — |
| | — |
| | 561 |
| | — |
| | — |
| | — |
|
Asset retirement obligations | 118 |
| | 79 |
| | 22 |
| | 16 |
| | 1 |
| | 1 |
| | — |
| | — |
|
MGP remediation costs | 326 |
| | 309 |
| | 17 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Renewable energy | 249 |
| | 249 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric Energy and Natural Gas Costs | 193 |
| | — |
| | 49 |
| | 51 |
| | 93 |
| | 84 |
| | — |
| | 9 |
|
Transmission formula rate annual reconciliations | 41 |
| | 6 |
| | — |
| | 4 |
| | 31 |
| | 10 |
| | 14 |
| | 7 |
|
Energy efficiency and demand response programs | 545 |
| | — |
| | 1 |
| | 289 |
| | 255 |
| | 188 |
| | 67 |
| | — |
|
Merger integration costs | 42 |
| | — |
| | — |
| | 3 |
| | 39 |
| | 18 |
| | 11 |
| | 10 |
|
Under-recovered revenue decoupling | 59 |
| | — |
| | — |
| | 2 |
| | 57 |
| | 57 |
| | — |
| | — |
|
Securitized stranded costs | 50 |
| | — |
| | — |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
Removal costs | 564 |
| | — |
| | — |
| | — |
| | 564 |
| | 158 |
| | 97 |
| | 309 |
|
DC PLUG charge | 159 |
| | — |
| | — |
| | — |
| | 159 |
| | 159 |
| | — |
| | — |
|
Deferred storm costs | 41 |
| | — |
| | — |
| | — |
| | 41 |
| | 9 |
| | 4 |
| | 28 |
|
Other | 303 |
| | 110 |
| | 24 |
| | 17 |
| | 162 |
| | 79 |
| | 28 |
| | 13 |
|
Total regulatory assets | 9,459 |
| | 1,600 |
| | 541 |
| | 575 |
| | 2,801 |
| | 913 |
| | 290 |
| | 426 |
|
Less: current portion | 1,222 |
| | 293 |
| | 81 |
| | 177 |
| | 489 |
| | 270 |
| | 59 |
| | 40 |
|
Total noncurrent regulatory assets | $ | 8,237 |
| | $ | 1,307 |
| | $ | 460 |
| | $ | 398 |
| | $ | 2,312 |
| | $ | 643 |
| | $ | 231 |
| | $ | 386 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory liabilities | | | | | | | | | | | | | | | |
Deferred income taxes | $ | 5,228 |
| | $ | 2,394 |
| | $ | — |
| | $ | 1,132 |
| | $ | 1,702 |
| | $ | 798 |
| | $ | 510 |
| | $ | 394 |
|
Nuclear decommissioning | 2,606 |
| | 2,217 |
| | 389 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Removal costs | 1,547 |
| | 1,368 |
| | — |
| | 52 |
| | 127 |
| | 20 |
| | 107 |
| | — |
|
Electric Energy and Natural Gas Costs | 294 |
| | 137 |
| | 132 |
| | 6 |
| | 19 |
| | — |
| | 18 |
| | 1 |
|
Other | 528 |
| | 227 |
| | 75 |
| | 79 |
| | 100 |
| | 11 |
| | 30 |
| | 25 |
|
Total regulatory liabilities | 10,203 |
| | 6,343 |
| | 596 |
| | 1,269 |
|
| 1,948 |
| | 829 |
| | 665 |
| | 420 |
|
Less: current portion | 644 |
| | 293 |
| | 175 |
| | 77 |
| | 84 |
| | 7 |
| | 59 |
| | 18 |
|
Total noncurrent regulatory liabilities | $ | 9,559 |
| | $ | 6,050 |
| | $ | 421 |
| | $ | 1,192 |
|
| $ | 1,864 |
| | $ | 822 |
| | $ | 606 |
| | $ | 402 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory assets | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | $ | 2,455 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Pension and other postretirement benefits - Merger related | 1,393 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deferred income taxes | 306 |
| | — |
| | 297 |
| | — |
| | 9 |
| | 9 |
| | — |
| | — |
|
AMI programs - Deployment costs | 385 |
| | — |
| | — |
| | 129 |
| | 101 |
| | 58 |
| | 43 |
| | — |
|
AMI programs - Legacy meters | 223 |
| | 155 |
| | 36 |
| | 53 |
| | 134 |
| | 100 |
| | 34 |
| | — |
|
AMI programs - Post-test year costs | 32 |
| | — |
| | — |
| | 32 |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution formula rate annual reconciliations | 186 |
| | 186 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution formula rate significant one-time events | 58 |
| | 58 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy efficiency costs | 166 |
| | 166 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fair value of long-term debt | 758 |
| | — |
| | — |
| | — |
| | 619 |
| | — |
| | — |
| | — |
|
Fair value of PHI's unamortized energy contracts | 750 |
| | — |
| | — |
| | — |
| | 750 |
| | — |
| | — |
| | — |
|
Asset retirement obligations | 109 |
| | 73 |
| | 22 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
|
MGP remediation costs | 295 |
| | 273 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Renewable energy | 258 |
| | 256 |
| | — |
| | — |
| | 2 |
| | — |
| | 1 |
| | 1 |
|
Electric energy and natural gas costs | 47 |
| | — |
| | 1 |
| | 16 |
| | 30 |
| | 8 |
| | 7 |
| | 15 |
|
Transmission formula rate annual reconciliations | 35 |
| | 6 |
| | — |
| | 7 |
| | 22 |
| | 3 |
| | 8 |
| | 11 |
|
Energy efficiency and demand response programs | 596 |
| | — |
| | 1 |
| | 285 |
| | 310 |
| | 229 |
| | 81 |
| | — |
|
Merger integration costs | 45 |
| | — |
| | — |
| | 6 |
| | 39 |
| | 20 |
| | 10 |
| | 9 |
|
Under-recovered revenue decoupling | 55 |
| | — |
| | — |
| | 14 |
| | 41 |
| | 38 |
| | 3 |
| | — |
|
Securitized stranded costs | 79 |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
|
Removal costs | 529 |
| | — |
| | — |
| | — |
| | 529 |
| | 150 |
| | 93 |
| | 286 |
|
DC PLUG charge | 190 |
| | — |
| | — |
| | — |
| | 190 |
| | 190 |
| | — |
| | — |
|
Deferred storm costs | 27 |
| | — |
| | — |
| | — |
| | 27 |
| | 7 |
| | 5 |
| | 15 |
|
Other | 311 |
| | 106 |
| | 31 |
| | 15 |
| | 165 |
| | 79 |
| | 29 |
| | 14 |
|
Total regulatory assets | 9,288 |
| | 1,279 |
| | 410 |
| | 571 |
|
| 3,047 |
| | 891 |
| | 314 |
| | 430 |
|
Less: current portion | 1,267 |
| | 225 |
| | 29 |
| | 174 |
| | 554 |
| | 213 |
| | 69 |
| | 71 |
|
Total noncurrent regulatory assets | $ | 8,021 |
| | $ | 1,054 |
| | $ | 381 |
| | $ | 397 |
|
| $ | 2,493 |
| | $ | 678 |
| | $ | 245 |
| | $ | 359 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory liabilities | | | | | | | | | | | | | | | |
Deferred income taxes | $ | 5,241 |
| | $ | 2,479 |
| | $ | — |
| | $ | 1,032 |
| | $ | 1,730 |
| | $ | 809 |
| | $ | 510 |
| | $ | 411 |
|
Nuclear decommissioning | 3,064 |
| | 2,528 |
| | 536 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Removal costs | 1,573 |
| | 1,338 |
| | — |
| | 105 |
| | 130 |
| | 20 |
| | 110 |
| | — |
|
Electric Energy and Natural Gas Costs | 111 |
| | 47 |
| | 60 |
| | — |
| | 4 |
| | — |
| | 1 |
| | 3 |
|
Other | 399 |
| | 185 |
| | 94 |
| | 26 |
| | 64 |
| | 3 |
| | 14 |
| | 8 |
|
Total regulatory liabilities | 10,388 |
| | 6,577 |
| | 690 |
| | 1,163 |
|
| 1,928 |
| | 832 |
| | 635 |
| | 422 |
|
Less: current portion | 523 |
| | 249 |
| | 141 |
| | 62 |
| | 56 |
| | 3 |
| | 42 |
| | 11 |
|
Total noncurrent regulatory liabilities | $ | 9,865 |
| | $ | 6,328 |
| | $ | 549 |
| | $ | 1,101 |
|
| $ | 1,872 |
| | $ | 829 |
| | $ | 593 |
| | $ | 411 |
|
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
|
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Pension and Other Postretirement Benefits | Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefit plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets. | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | No |
Pension and Other Postretirement Benefits - Merger Related | The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets. | Legacy Constellation - 2038 Legacy PHI - 2032 | No |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Deferred Income Taxes | Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information. | Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules. | No |
AMI Programs - Deployment Costs | Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters. | BGE - 2026 Pepco - 2027 DPL - 2030 | Yes |
AMI Programs - Legacy Meters | Early retirement costs of legacy meters. | ComEd - 2028 PECO - 2020 BGE - 2028 Pepco - 2027 DPL - 2030 | ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No |
AMI Programs - Post-test year incremental costs | Post-test year incremental program deployment costs of smart meters. As of December 31, 2018 and 2017, the portion of BGE's regulatory asset related to gas and electric costs was $10 million and $22 million, respectively.
| BGE (gas) - 2021 BGE (electric) - Not currently being recovered. | BGE (gas) - Yes BGE (electric) - No |
Electric distribution formula rate annual reconciliations
| Under-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1st. | 2020
| Yes |
Electric distribution formula rate significant one-time events
| Under-recoveries of electric distribution service costs related to significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event. | 2022 | Yes |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Energy Efficiency Costs
| Costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure. | 2029 | Yes
|
Fair Value of Long-Term Debt
| Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $569 million and $133 million, respectively, as of December 30, 2018 and $619 million and $139 million, respectively, as of December 30, 2017, as of the PHI and Constellation merger dates. | BGE - 2043 PHI - 2045 | No |
Fair Value of PHI’s Unamortized Energy Contracts
| Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date. | 2036 | No |
Asset Retirement Obligations | Future legally required removal costs associated with existing asset retirement obligations. | Over the life of the related assets. | Yes, once the removal activities have been performed. |
MGP Remediation Costs
| Environmental remediation costs for MGP sites.
| Over the expected remediation period. See Note 22 - Commitments and Contingencies for additional information. | ComEd, PECO - No |
Renewable Energy | Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts. | 2032
| No |
Electric Energy and Natural Gas Costs | Under (over) recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders. | 2025 | DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No |
Transmission formula rate annual reconciliations
| Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1st.
| 2020 | Yes |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | |
Line Item | Description | End Date of Remaining Recovery/Refund Period | Return |
Energy efficiency and demand response programs
| Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.
| PECO - 2021 BGE - 2023 Pepco, DPL - 2033 | BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism
|
Merger Integration Costs | Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $9 million each as of December 31, 2018 and $11 million and $9 million, respectively, as of December 31, 2017. | BGE - 2021 Pepco - 2021 DPL- 2023 ACE - Not currently being recovered. | BGE, Pepco (Maryland), DPL - Yes Pepco (District of Columbia), ACE - No |
Under (Over)-Recovered Revenue Decoupling
| Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms. | BGE, Pepco and DPL - 2019 | BGE, Pepco, DPL- No |
Securitized Stranded Costs
| Represents certain stranded costs associated with ACE's former electricity generation business.
| 2022
| Yes |
Removal Costs
| For PHI, Pepco, DPL and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes. | PHI, Pepco, DPL and ACE - Asset is generally recovered over the life of the underlining assets.
ComEd, BGE, PHI, Pepco and DPL - The liability is reduced as costs are incurred.
| Yes |
DC PLUG Charge
| Costs associated with the DC Plug Initiative. See District of Columbia Regulatory Matters discussion above. | 2019 - $30M $127 million to be determined based on future biennial plans filed with the DCPSC. | Portion of asset funded by Pepco-Yes
|
Deferred Storm Costs | For Pepco, DPL and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions. | Pepco - 2022
DPL - 2023
ACE - 2020 | Pepco, DPL - Yes
ACE - No |
Nuclear Decommissioning
| Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 15 - Asset Retirement Obligations for additional information | Not currently being refunded.
| No |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Capitalized Ratemaking Amounts Not Recognized
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
December 31, 2018 | $ | 65 |
| | $ | 8 |
| | $ | — |
| | $ | 49 |
| | $ | 8 |
| | $ | 5 |
| | $ | 3 |
| | $ | — |
|
| | | | | | | | | | | | | | | |
December 31, 2017 | $ | 69 |
| | $ | 6 |
| | $ | — |
| | $ | 53 |
| | $ | 10 |
| | $ | 6 |
| | $ | 4 |
| | $ | — |
|
__________
| |
(a) | Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets. |
| |
(b) | BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs. |
| |
(c) | Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only. |
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard.Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. For the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits, which were granted by the district court. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. The U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the plaintiffs’ request for rehearing on October 9, 2018. On January 7, 2019, plaintiffs filed a petition seeking Supreme Court review of the case.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that will establish a ZEC program providing compensation for nuclear plants that demonstrate to the NJBPU approvedthat they meet certain requirements, including that they make a stipulationsignificant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
will be required to purchase those ZECs. Selected nuclear plants will receive annual ZEC payments for each energy year (12-month period from June 1 through May 31) within 90 days after the completion of settlement entered intosuch energy year. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the parties providing for an overall annual rate decreasepublic electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $32 million, effective June 1, 2017. The rate decrease was placed into effect provisionally, subject$10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to a review by NJBPU andreduce the Division of Rate Counsel of the final underlying costs for reasonableness and prudence. This rate decrease will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.ZEC price. On November 1, 2017, ACE entered into a Stipulation of Final Rates with the NJBPU staff and the New Jersey Division of Rate Counsel which was unchanged from the provisional rates. On November 21, 2017,19, 2018, the NJBPU issued an order approvingproviding for the Stipulationmethod and application process for determining the eligibility of Final Rates as filed.
2016 Updatenuclear power plants, a draft method and Reconciliationprocess for ranking and selecting eligible nuclear power plants, and the establishment of Certain Under-Recovered Balances (Exelon, PHIa mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and ACE). Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On February 1, 2016, ACE submitted its 2016 annual petitionthe same day, Generation filed certain Supplemental Information with the NJBPU seekingproviding proprietary information that was requested in the application but which could not be shared with PSEG. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-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.PSEG’s Salem nuclear plant.
As filed, the net impact of adjusting the charges as proposed would have been 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.
On November 30, 2016, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate increase of $1 million effective January 1, 2017. This settlement included a credit of approximately $10 million to the Non-Utility Generation charge deferral balance and a credit of approximately $7 million to the Uncollectible deferral balance. These credits were directed to be applied to the deferral balances in an NJBPU order dated October 31, 2016. That order approved the Joint Recommendation for Settlement of the Most Favored Nation Provision, which was a condition of the merger between Exelon Corporation and Pepco Holdings, Inc. This rate increase will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.
New York Regulatory Matters
New York Clean Energy Standard (Exelon and Generation). Standard.On August 1, 2016, the New York Public Service Commission (NYPSC)NYPSC issued an order establishing the New York CES, a component of which isincluded a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet themet specific criteria demonstrating public necessity, as determined by the NYPSC.NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) will centrally procureprocures 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, 2029.2029, administered in six two-year tranches. ZEC payments will beare made to the eligible resources based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price to be paid for the ZECs under eachfirst tranche will bewas set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. The ZEC price for the first tranche has been set at $17.48 per
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) shall beis required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers shall beis incorporated into the commodity charges on customer bills.
The NYPSC initially identified three plants eligible for the ZEC program: the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility. On March 31, 2017, Generation closed on the acquisition of FitzPatrick. Generation is currently recognizing revenue for the sale of New York ZECs in the month following generation whenthey are generated and for the ZECs are transferred to NYSERDA. For the yearyears ended December 31, 2018 and 2017, Generation has recognized revenue of $438 million and $311 million, of ZEC revenue.
Several parties filed with the NYPSC requests for rehearing or reconsideration of the New York CES. 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 full 12-year duration. On December 15, 2016, the NYPSC approved Exelon’s petition to clarify this condition and denied all petitions for rehearing of the New York CES. Parties had until mid-April 2017 to appeal to New York State court the denials of the requests for rehearing.respectively.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENGseveral parties filed a motionmotions to intervene in the case and to dismiss the lawsuit. The State also filed a motion to dismiss. On July 25, 2017, the court granted boththe motions to dismiss. On August 24, 2017, plaintiffs appealedSeptember 27, 2018, the decision toU.S. Court of Appeals for the Second Circuit. Plaintiffs-Appellants' initial brief wasCircuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed on October 13, 2017. Briefing ina petition seeking Supreme Court review of the appeal was completed in December 2017, and oral argument is expected to take place in March 2018.case.
In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties including certain environmental groups and individuals, filed a Petition in New York State court seeking to invalidate the ZEC program. The Petition,program, which was amended on January 13, 2017, argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program. On February 15, 2017,Subsequently, Generation, CENG and CENGthe NYPSC filed a motionmotions to dismiss the state court action. The NYPSC also filed a motion to dismissaction, which were later opposed by 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. Oral argument was held on June 19, 2017.plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. Generation, CENG and the state's answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. After briefing is completed, the court will decide whether or not to set the case will now proceedfor hearing.
Combined Notes to summary judgment upon filing of the full record.Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 - Early Nuclear Plant Retirements for additional information relativerelated to Ginna and Nine Mile Point, and Note 45 - 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). Agreement.In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA)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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 the ISO-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 theGinna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of 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 the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Upon the expiry of the RSSA on March 31, 2017, Ginna was required to make refund payments of $20 million to RG&E related to capital expenditures. Ginna paid RG&E the $20 million in June 2017. Additionally, the provisions of the RSSA provided for a one-time payment of $12 million to be paid from RG&E to Ginna at the end of the contract. This $12 million was recognized in revenue as of March 31, 2017. RG&E paid the $12 million to Ginna in May 2017. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 8 - Early Nuclear Plant Retirements for furtheradditional information regarding the impacts of a decision to early retire one or morea nuclear plants.plant.
Federal Regulatory Matters
Tax Cuts and Jobs Act (All Registrants). To date, the FERC has not yet issued guidance to utilities on how and when to reflect the impacts of the TCJA in customer rates. However, pursuant to their respective transmission formula rates, ComEd, BGE, Pepco, DPL and ACE will begin passing back to customers on June 1, 2018, the benefit of lower income tax rates effective January 1, 2018. ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income tax-related regulatory liabilities or assets. As discussed above, on December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate and on December 18, 2017, BGE filed for clarification and rehearing of FERC’s order. ComEd, Pepco, DPL and ACE also have similar transmission-related income tax regulatory assets and liabilities, for which FERC approval is required, separate from their transmission formula rate mechanisms, to pass back or recover those regulatory liabilities and assets through customer rates. PECO is currently in settlement discussions regarding its transmission formula rate and expects to pass back TCJA benefits to customers through its annual formula rate update.
Refer to Deferred income taxes in the Regulatory Assets and Liabilities section below for the balances of transmission-related income tax regulatory assets as of December 31, 2017 and 2016.
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
For each of the following years, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| ComEd | | BGE |
Annual Transmission Filings(a) | 2017 |
| 2016 |
| 2015 | | 2017 | | 2016 | | 2015 |
Initial revenue requirement increase | $ | 44 |
| | $ | 90 |
| | $ | 68 |
| | $ | 31 |
| | $ | 12 |
| | $ | — |
|
Annual reconciliation increase (decrease) | (33 | ) | | 4 |
| | 18 |
| | 3 |
| | 3 |
| | (3 | ) |
Dedicated facilities (decrease) increase(b) | — |
| | — |
| | — |
| | (8 | ) | | 13 |
| | 13 |
|
Total revenue requirement increase | $ | 11 |
| | $ | 94 |
| | $ | 86 |
| | $ | 26 |
| | $ | 28 |
| | $ | 10 |
|
| | | | | | | | | | | |
Allowed return on rate base(d) | 8.43 | % | | 8.47 | % | | 8.61 | % | | 7.47 | % | | 8.09 | % | | 8.46 | % |
Allowed ROE(e) | 11.50 | % | | 11.50 | % | | 11.50 | % | | 10.50 | % | | 10.50 | % | | 11.30 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
Annual Transmission Filings(a) | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
Initial revenue requirement increase (decrease) | $ | 5 |
| | $ | 2 |
| | $ | 10 |
| | $ | 6 |
| | $ | 8 |
| | $ | 15 |
| | $ | 20 |
| | $ | 8 |
| | $ | 10 |
|
Annual reconciliation (decrease) increase | 15 |
| | (10 | ) | | (3 | ) | | 8 |
| | (10 | ) | | (1 | ) | | 22 |
| | (14 | ) | | 2 |
|
MAPP abandonment recovery (decrease) increase(c) | — |
| | (15 | ) | | (2 | ) | | — |
| | (12 | ) | | (2 | ) | | — |
| | — |
| | — |
|
Total revenue requirement (decrease) increase | $ | 20 |
| | $ | (23 | ) | | $ | 5 |
| | $ | 14 |
| | $ | (14 | ) | | $ | 12 |
| | $ | 42 |
| | $ | (6 | ) | | $ | 12 |
|
| | | | | | | | | | | | | | | | | |
Allowed return on rate base(d) | 7.92 | % | | 7.88 | % | | 8.36 | % | | 7.16 | % | | 7.21 | % | | 7.80 | % | | 8.02 | % | | 7.83 | % | | 8.51 | % |
Allowed ROE(e) | 10.50 | % | | 10.50 | % | | 11.30 | % | | 10.50 | % | | 10.50 | % | | 11.30 | % | | 10.50 | % | | 10.50 | % | | 11.30 | % |
__________
| |
(a) | The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted. |
| |
(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) | In 2012, PJM terminated the MAPP transmission line construction project planned for the Pepco and DPL service territories. Pursuant to a FERC approved settlement agreement, the abandonment costs associated with MAPP were being recovered in transmission rates over a three-year period that ended in May 2016. |
| |
(d) | Represents to the weighted average debt and equity return on transmission rate bases. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(e) | As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO. |
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. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. The parties currently are engaged in settlement discussions. PECO cannot predict the final outcome of the settlement or hearing proceedings, or the transmission formula FERC may approve.
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax regulatory asset amounts.
ComEd, Pepco, DPL and ACE have similar transmission-related income tax regulatory assets also requiring FERC approval separate from their transmission formula rate mechanisms. Similar regulatory assets at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by the November 16, 2017 FERC order.
Each of BGE, ComEd, Pepco, DPL and ACE believe there is sufficient basis to support full recovery of their existing transmission-related income tax regulatory assets, and each intends to further pursue such full recovery with FERC. However, upon further consideration of the November 16, 2017 FERC order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded the following charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter 2017, reducing their associated transmission-related income tax regulatory assets.
|
| | | |
| For the year ended December 31, 2017 |
Exelon(a) | $ | 35 |
|
ComEd | 3 |
|
BGE | 5 |
|
PHI(a) | 27 |
|
Pepco | 14 |
|
DPL | 6 |
|
ACE | 7 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
(a) Exelon reflects the consolidated regulatory asset impairments of ComEd, BGE, Pepco, DPL and ACE, and PHI reflects the consolidated regulatory asset impairments of Pepco, DPL and ACE.
To the extent any of the companies are ultimately successful with the FERC allowing future recovery of these amounts, the associated regulatory assets will be reestablished, with corresponding decreases to Income tax expense. To the extent all or a portion of the prospective amortization amounts were no longer considered probable of recovery, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $81 million, $41 million, $22 million, $18 million, $8 million, $7 million and $3 million, respectively, as of December 31, 2017.
Refer to Deferred income taxes in the Regulatory Assets and Liabilities section below for the balances of these transmission-related income tax regulatory assets as of December 31, 2017 and 2016.
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 a 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 did not oppose, the settlement. The Settlement is opposed by a number of merchant transmission owners and 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 a 10-year period based on negotiated numbers for charges prior to January 1, 2016.
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. The FERC is not required to issue a decision on the matter within a specified period of time.
The Utility Registrants are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. The Utility Registrants will work with PJM to continue to evaluate the scope and timing of any required construction projects. The Utility Registrants' estimated commitments are as follows:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | 2018 | | 2019 | | 2020 | | 2021 | | 2022 |
ComEd | $ | 164 |
| | $ | 36 |
| | $ | 60 |
| | $ | 44 |
| | $ | 24 |
| | $ | — |
|
PECO | 53 |
| | 16 |
| | 19 |
| | 10 |
| | 5 |
| | 3 |
|
BGE | 118 |
| | 35 |
| | 35 |
| | 35 |
| | 13 |
| | — |
|
Pepco | 86 |
| | 5 |
| | 11 |
| | 27 |
| | 33 |
| | 10 |
|
DPL | 27 |
| | 19 |
| | 2 |
| | 1 |
| | 2 |
| | 3 |
|
ACE | 121 |
| | 68 |
| | 20 |
| | 6 |
| | 21 |
| | 6 |
|
DOE Notice of Proposed Rulemaking (Exelon and Generation). On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that the electricity markets do not currently value the resiliency provided by baseload generation, such as nuclear plants. On September 28, 2017, the DOE issued a Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a fair return on equity on their investment. The DOE's NOPR recommended that the FERC take comments for 45 days after publication in the Federal Register and issue a final order 60 days after such publication. On January 8, 2018, the FERC issued an order terminating the rulemaking docket that was initiated to address the proposed rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, the FERC initiated a new proceeding to consider resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. The FERC directed each RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Interested parties may submit reply comments within 30 days after the due date of the RTO/ISO responses. Exelon has been and will continue to be an active participant in these proceedings, but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
Complaints 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. The EPSA parties have filed motions to expedite both proceedings. 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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
the PTC and RPS that have generally not been subject to a MOPR. However, if successful, for Generation's facilities in NYISO and PJM 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. On August 30, 2017, EPSA filed motions to lodge the district court decisions dismissing the complaints and urging FERC to act expeditiously on its requests to expand the MOPR. On September 14, 2017, Exelon filed a response in each docket noting that it does not oppose the motions to lodge but arguing that the requests to expedite a decision on the requests to expand the MOPR have no merit. 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).
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-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 (401 Certification) 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.
On April 21, 2016, ExelonGeneration and the USU.S. Fish and Wildlife Service of the USU.S. Department of the Interior executed a Settlement Agreement resolving all fish passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-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 ofOn April 27, 2018, the remaining issuesMDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to Conowingo involving various stakeholders mayreduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, effectunfavorable impact on Exelon’s and Generation’s results of operations and financial positionsstatements through an increase in capital expenditures and operating costs. costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer action on the federal license while these significant state and federal law issues are pending. On July 9, 2018, MDE filed a motion to dismiss Generation's complaint in state court, which was granted without prejudice on October 9, 2018. The court found MDE's Certification was not a "final decision" of Exelon's rights and because Exelon's motion for reconsideration remains pending, as does its administrative appeal of the 401 Certification, there was no final administrative decision for the court to review at this time. On November 5, 2018, Exelon appealed the Maryland Circuit Court's dismissal of Exelon's state complaint. Exelon continues to challenge the 401 Certification through the administrative process and in federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation.
As of December 31, 2017, $312018, $37 million of direct costs associated with Conowingo licensing efforts have been capitalized.
Regulatory AssetsPeach Bottom Units 2 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 accordance3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the authoritative guidanceNRC 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 representPeach Bottom Units 2 and 3. Generation anticipates the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returnedsecond license renewal process 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 December 31, 2017 and December 31, 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory assets | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | $ | 3,848 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Deferred income taxes | 306 |
| | — |
| | 297 |
| | — |
| | 9 |
| | 9 |
| | — |
| | — |
|
AMI programs | 640 |
| | 155 |
| | 36 |
| | 214 |
| | 235 |
| | 158 |
| | 77 |
| | — |
|
Electric distribution formula rate | 244 |
| | 244 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy efficiency costs | 166 |
| | 166 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Debt costs | 116 |
| | 37 |
| | 1 |
| | 11 |
| | 73 |
| | 15 |
| | 8 |
| | 5 |
|
Fair value of long-term debt | 758 |
| | — |
| | — |
| | — |
| | 619 |
| | — |
| | — |
| | — |
|
Fair value of PHI's unamortized energy contracts | 750 |
| | — |
| | — |
| | — |
| | 750 |
| | — |
| | — |
| | — |
|
Asset retirement obligations | 109 |
| | 73 |
| | 22 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
|
MGP remediation costs | 295 |
| | 273 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Under-recovered uncollectible accounts | 61 |
| | 61 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Renewable energy | 258 |
| | 256 |
| | — |
| | — |
| | 2 |
| | — |
| | 1 |
| | 1 |
|
Energy and transmission programs | 82 |
| | 6 |
| | 1 |
| | 23 |
| | 52 |
| | 11 |
| | 15 |
| | 26 |
|
Deferred storm costs | 27 |
| | — |
| | — |
| | — |
| | 27 |
| | 7 |
| | 5 |
| | 15 |
|
Energy efficiency and demand response programs | 596 |
| | — |
| | 1 |
| | 285 |
| | 310 |
| | 229 |
| | 81 |
| | — |
|
Merger integration costs | 45 |
| | — |
| | — |
| | 6 |
| | 39 |
| | 20 |
| | 10 |
| | 9 |
|
Under-recovered revenue decoupling | 55 |
| | — |
| | — |
| | 14 |
| | 41 |
| | 38 |
| | 3 |
| | — |
|
COPCO acquisition adjustment | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
| | — |
|
Workers compensation and long-term disability costs | 35 |
| | — |
| | — |
| | — |
| | 35 |
| | 35 |
| | — |
| | — |
|
Vacation accrual | 19 |
| | — |
| | 6 |
| | — |
| | 13 |
| | — |
| | 8 |
| | 5 |
|
Securitized stranded costs | 79 |
| | — |
| | — |
| | — |
| | 79 |
| | — |
| | — |
| | 79 |
|
CAP arrearage | 8 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Removal costs | 529 |
| | — |
| | — |
| | — |
| | 529 |
| | 150 |
| | 93 |
| | 286 |
|
DC PLUG charge | 190 |
| | — |
| | — |
| | — |
| | 190 |
| | 190 |
| | — |
| | — |
|
Other | 67 |
| | 8 |
| | 16 |
| | 4 |
| | 39 |
| | 29 |
| | 8 |
| | 4 |
|
Total regulatory assets | 9,288 |
| | 1,279 |
| | 410 |
| | 571 |
|
| 3,047 |
|
| 891 |
|
| 314 |
|
| 430 |
|
Less: current portion | 1,267 |
| | 225 |
| | 29 |
| | 174 |
| | 554 |
| | 213 |
| | 69 |
| | 71 |
|
Total noncurrent regulatory assets | $ | 8,021 |
| | $ | 1,054 |
| | $ | 381 |
| | $ | 397 |
|
| $ | 2,493 |
|
| $ | 678 |
|
| $ | 245 |
|
| $ | 359 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory liabilities | | | | | | | | | | | | | | | |
Other postretirement benefits | $ | 30 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Deferred income taxes | 5,241 |
| | 2,479 |
| | — |
| | 1,032 |
| | $ | 1,730 |
| | 809 |
| | 510 |
| | 411 |
|
Nuclear decommissioning | 3,064 |
| | 2,528 |
| | 536 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Removal costs | 1,573 |
| | 1,338 |
| | — |
| | 105 |
| | 130 |
| | 20 |
| | 110 |
| | — |
|
Deferred rent | 36 |
| | — |
| | — |
| | — |
| | 36 |
| | — |
| | — |
| | — |
|
Energy efficiency and demand response programs | 23 |
| | 4 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
DLC program costs | 7 |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution tax repairs | 35 |
| | — |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Gas distribution tax repairs | 9 |
| | — |
| | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy and transmission programs | 111 |
| | 47 |
| | 60 |
| | — |
| | 4 |
| | — |
| | 1 |
| | 3 |
|
Renewable portfolio standards costs | 63 |
| | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Zero emission credit costs | 112 |
| | 112 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Over-recovered uncollectible accounts | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Other | 82 |
| | 6 |
| | 24 |
| | 26 |
| | 26 |
| | 3 |
| | 14 |
| | 6 |
|
Total regulatory liabilities | 10,388 |
| | 6,577 |
| | 690 |
| | 1,163 |
|
| 1,928 |
|
| 832 |
|
| 635 |
|
| 422 |
|
Less: current portion | 523 |
| | 249 |
| | 141 |
| | 62 |
| | 56 |
| | 3 |
| | 42 |
| | 11 |
|
Total noncurrent regulatory liabilities | $ | 9,865 |
| | $ | 6,328 |
| | $ | 549 |
| | $ | 1,101 |
|
| $ | 1,872 |
|
| $ | 829 |
|
| $ | 593 |
|
| $ | 411 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
December 31, 2016 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory assets | | | | | | | | | | | | | | | |
Pension and other postretirement benefits | $ | 4,162 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Deferred income taxes | 2,016 |
| | 75 |
| | 1,583 |
| | 98 |
| | 260 |
| | 171 |
| | 38 |
| | 51 |
|
AMI programs | 701 |
| | 164 |
| | 49 |
| | 230 |
| | 258 |
| | 174 |
| | 84 |
| | — |
|
Electric distribution formula rate | 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 |
| | — |
| | — |
| | — |
|
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 | 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 | 25 |
| | — |
| | — |
| | 10 |
| | 15 |
| | 11 |
| | 4 |
| | — |
|
Under-recovered revenue decoupling | 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 | 54 |
| | 7 |
| | 9 |
| | 10 |
| | 29 |
| | 22 |
| | 5 |
| | 4 |
|
Total regulatory assets | 11,388 |
| | 1,167 |
| | 1,710 |
| | 712 |
|
| 3,504 |
|
| 852 |
|
| 348 |
|
| 501 |
|
Less: current portion | 1,342 |
| | 190 |
| | 29 |
| | 208 |
| | 653 |
| | 162 |
| | 59 |
| | 96 |
|
Total noncurrent regulatory assets | $ | 10,046 |
| | $ | 977 |
| | $ | 1,681 |
| | $ | 504 |
|
| $ | 2,851 |
|
| $ | 690 |
|
| $ | 289 |
|
| $ | 405 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
December 31, 2016 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Regulatory liabilities | | | | | | | | | | | | | | | |
Other postretirement benefits | $ | 47 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Nuclear decommissioning | 2,607 |
| | 2,169 |
| | 438 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Removal costs | 1,601 |
| | 1,324 |
| | — |
| | 141 |
| | 136 |
| | 18 |
| | 118 |
| | — |
|
Deferred rent | 39 |
| | — |
| | — |
| | — |
| | 39 |
| | — |
| | — |
| | — |
|
Energy efficiency and demand response programs | 185 |
| | 141 |
| | 41 |
| | — |
| | 3 |
| | 3 |
| | — |
| | — |
|
DLC program costs | 8 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Electric distribution tax repairs | 76 |
| | — |
| | 76 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Gas distribution tax repairs | 20 |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy and transmission programs | 134 |
| | 60 |
| | 56 |
| | — |
| | 18 |
| | 8 |
| | 5 |
| | 5 |
|
Other | 72 |
| | 4 |
| | 5 |
| | 19 |
| | 41 |
| | 2 |
| | 17 |
| | 20 |
|
Total regulatory liabilities | 4,789 |
| | 3,698 |
| | 644 |
| | 160 |
|
| 237 |
|
| 31 |
|
| 140 |
|
| 25 |
|
Less: current portion | 602 |
| | 329 |
| | 127 |
| | 50 |
| | 79 |
| | 11 |
| | 43 |
| | 25 |
|
Total noncurrent regulatory liabilities | $ | 4,187 |
| | $ | 3,369 |
| | $ | 517 |
| | $ | 110 |
|
| $ | 158 |
|
| $ | 20 |
|
| $ | 97 |
|
| $ | — |
|
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods. Unless otherwise noted, the Utility Registrants are not earning or paying a return on these amounts.
Pension and other postretirement benefits. PECO’s regulatory recovery for pension is based on cash contributions and, thus, is not included in the regulatory asset balances above. Otherwise, these amounts represent the Utility Registrants’ portion of deferred costs associated with Exelon’s pension and other postretirement benefit plans, which are recovered through customer rates. These amounts are generally amortized over the plan participants’ average remaining service periods, subject to applicable cost recognition policies allowed under the authoritative guidance for pensions and postretirement benefits. See Note 16 - Retirement Benefits for additional information. These amounts also include regulatory assets established at the Constellation and PHI merger dates of $440 million and $953 million, respectively, as of December 31, 2017 and $492 million and $1,027 million, respectively, as of December 31, 2016 related to the rate regulated portions of the deferred costs associated with legacy Constellation’s and PHI’s pension and other postretirement benefit plans that are being amortized and recovered over approximately 12 years and 3 to 15 years, respectively (as established at the respective acquisition dates).
Deferred income taxes. These amounts represent deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of the allowance for funds used during construction, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts are being amortized over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets, but may vary for certain deferred income taxes based on the determination of the rate regulators. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate of $484 million, $137 million, $147 million, $148 million and $147 million for ComEd, BGE, Pepco, DPL and ACE, respectively, as of December 31, 2017. The December 31, 2017 balances reflect the impact of regulatory liabilities recorded in the fourth quarter, 2017 associated with the income tax rate reductions under the TCJA of $553 million, $174 million, $161 million, $160 million and $152 million for ComEd, BGE, Pepco, DPL and ACE, respectively, as well as the impact of impairment charges discussed above. As of December 31, 2016 the comparative amounts are a regulatory asset of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. See Note 14— Income Taxes and the Transmission-Related Income Tax Regulatory Assets section above for additional information.take
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
AMI programs. For ComEd, this amount primarily represents accelerated depreciation costs resultingapproximately 2 years from the early retirements of non-AMI meters, which will be amortized over an average ten-year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the regulatory asset.
For PECO, this amount primarily represents accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. Recovery of smart meter costs are reflected in base rates effective January 1, 2016.
For BGE, this amount represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters. The incremental costs associated with the installation, along with depreciation, amortization, and an appropriate return, had been building in a regulatory asset since the MDPSC approved the comprehensive smart grid initiative for BGE in August 2010 through approvalapplication submission until completion of the program in BGE’s rate order issued June 2016. As of December 31, 2017, the balance of BGE’s regulatory asset was $214 million, which consists of three major components, including $129 million of unamortized incremental deployment costs of the AMI program, $53 million of unamortized costs of the non-AMI meters replaced under the program,NRC’s review process. Peach Bottom Units 2 and $32 million related3 are currently licensed to post-test year incremental program deployment costs incurred prioroperate through 2033 and 2034, respectively.
PJM Transmission Rate Design. Refer to approval became effective June 2016. As of December 31, 2016, the balance of BGE’s regulatory asset was $230 million, which consists of three major components, including $144 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-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 balancesOther Federal Regulatory Matters above reflect the impact of the cost allowances and adjustments in BGE's 2015 electric and natural gas distribution rate case. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being amortized and recovered through rates over a 10-year period, which began in June 2016, 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 portion representing the unamortized cost of the retired non-AMI meters and the portion related to post-test year incremental program deployment costs.
For PHI, this amount represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. Pepco has received approval for recovery of deferred AMI program costs from the DCPSC and the MDPSC in its District of Columbia and Maryland service territories. Pepco does earn a return on the AMI deployment costs, but not on the early retirement of legacy meters. DPL has received approval for recovery of deferred AMI program costs from the DPSC and the MDPSC in its Delaware and Maryland service territories. DPL earns a return on the AMI deployment costs, but not on the early retirement of legacy meters.
Electric Distribution Formula Rate. These amounts represent under recoveries related to electric distribution services costs recoverable through ComEd’s performance based formula rate. Under (over) recoveries for the annual reconciliations are recoverable (refundable) over a one-year period and costs for certain one-time events, such as large storms, are recoverable over a five-year period. ComEd earns and pays a return on under and over-recovered costs, respectively. As of December 31, 2017, the regulatory asset was comprised of $186 million for the 2016 and 2017 annual reconciliations and $58 million related to significant one-time events. As of December 31, 2016, the regulatory asset of $188 million was comprised of $134 million for the 2015 and 2016 annual reconciliations and $54 million related to significant one-time events.
Energy efficiency costs. These amounts represent deferred energy efficiency costs beginning June 1, 2017 that will be recovered through ComEd's energy efficiency formula rate tariff over the weighted average useful life of the related energy efficiency measures. The balance also includes the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
requirement based on actual prior year costs. ComEd earns a return on the energy efficiency regulatory asset.
Debt costs. The Utility Registrants’ debt costs are used in the determination of their weighted average cost of capital, which is applied to rate base for rate-making purposes. Consistent with the treatment for ratemaking purposes, ComEd’s, PECO’s, and Pepco’s recoverable losses or refundable gains on reacquired long-term debt are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced, while BGE’s, DPL’s, and ACE’s recoverable losses or refundable gains on reacquired long-term debt are deferred and amortized to interest expense over the life of the original debt issuance even if the debt was refinanced. The regulatory asset for Pepco, DPL and ACE as of March 23, 2016 was eliminated at Exelon and PHI as part of acquisition accounting.
Fair value of long-term debt. These amounts represent the unamortized regulatory assets recorded at Exelon for the difference between the carrying value and fair value of the long-term debt of BGE as of the Constellation merger date based on the MDPSC practice to allow BGE to recover its debt costs through rates and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL and ACE as of the PHI Merger date. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt.
Fair value of PHI's unamortized energy contracts. These amounts represent the regulatory asset recorded at Exelon and PHI offsetting the fair value adjustments related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI Merger date. Pepco, DPL and ACE are allowed full recovery of the costs of these contracts through their respective rate making processes.
Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd and BGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. The recovery period will be over the expected life of the related assets. See Note 15 — Asset Retirement Obligations for additional information.
MGP remediation costs. ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures, currently estimated to be completed in 2022 for both ComEd and PECO. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. BGE is earning a return on this regulatory asset and these costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. The recovery period for the 10-year period that began January 2006 was extended for an additional 24 months, in accordance with the MDPSC approved 2014 electric and natural gas distribution rate case order. See Note 23 — Commitments and Contingencies for additional information.
Under-recovered uncollectible accounts. These amounts represent the difference between ComEd’s annual uncollectible accounts expense and revenues collected in rates through an ICC-approved rider. The difference between net uncollectible account charge-offs and revenues collected through the rider each calendar year is recovered or refunded over a twelve-month period beginning in June of the following calendar year.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Renewable energy. In December 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs through 2032 in order to meet a portion of its obligations under the Illinois RPS. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). Recovery of these costs will continue through 2032. The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy at the market price and the contracted price.
Beginning with the 2012 compliance year the DPSC required DPL to be responsible for the RPS compliance obligation with respect to energy delivered to all end use customers, including RES supplied customers. This obligation has been met by DPL entering into long term contract(s) for the procurement of renewable energy. This energy is then sold into the market at current energy prices to offset the net cost to customers. An RPS surcharge is billed to customers to ensure recovery of the procurement costs with any variance recorded as an asset or liability. The balance at year end represents an under-recovery of the net procurement costs. These costs will be recovered over the life of the contracts, which range from 15 to 20 years.
In 2008 the NJBPU directed ACE to file a program for the purchase of Solar Renewable Energy Credits (SREC’s). In 2009 the NJBPU approved ACE’s SREC based contracting program and authorized ACE to enter into long-term contracts to purchase SREC’s generated by solar generation projects. ACE is required to auction the purchased SREC’s under Purchase and Sale Agreements (PSA) with the solar project developers. In 2015 the NJBPU authorized a “phase II” SREC program. A Regional Greenhouse Gas Initiative (RGGI) surcharge rider ensures recovery of the SREC costs. The balance at year end represents an under-recovery of the SREC costs. These costs will be recovered over the life of the contracts, which range from 15 to 20 years.
Energy and transmission programs. These amounts represent under (over) recoveries related to energy and transmission costs recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. Under (over) recoveries are recoverable (refundable) over a one-year period or less. ComEd earns a return or interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2017, ComEd's regulatory asset of $6 million represents transmission costs recoverable through its FERC approved formula rate. As of December 31, 2017, ComEd's regulatory liability of $47 million included $14 million related to over-recovered energy costs and $33 million associated with revenues received for renewable energy requirements. As of December 31, 2016, ComEd's regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC-approved formula rate tariff and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd's regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements. See Transmission Formula Rate above for further details.
The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO’s GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. In addition, the DSP Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO’s PAPUC-approved DSP programs for the procurement of electric supply. The filings and procurements of these DSP Programs are recoverable through the GSA over each respective term. DSP III has a 24-month term that began June 1, 2015, and DSP IV has a 48-month term that began June 1, 2017. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
of the procurements. PECO is not earning a return on these costs. Certain costs included in PECO's original DSP program related to information technology improvements were recovered over a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology costs. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2017, PECO's regulatory liability of $60 million included $36 million related to over-recovered costs under the DSP program, $12 million related to over-recovered non-bypassable transmission service charges and $12 million related to the over-recovered natural gas costs under the PGC. 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-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to over-recovered electric transmission costs.
The BGE energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers under BGE’s market-based SOS program, MBR program, and FERC approved transmission rates, respectively. BGE earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. BGE does not earn or pay interest to customers on under-recovered or over-recovered SOS and MBR costs. The recovery or refund period is a twelve-month period beginning in June of the following calendar year. As of December 31, 2017, BGE's regulatory asset of $23 million included $7 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $5 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $8 million related to under-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 related to under-recovered natural gas costs.
The Pepco energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under Pepco’s market-based SOS program and FERC approved transmission rates. Pepco earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. Pepco does not earn or pay interest to customers on under- or over-recovered SOS costs. The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2017, Pepco's regulatory asset of $11 million included $3 million of transmission costs recoverable through its FERC approved formula rate and $8 million of under-recovered electric energy costs. As of December 31, 2017, Pepco's regulatory liability was zero. 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.
The DPL energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers under DPL’s market-based SOS program, GCR and FERC approved transmission rates. DPL earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. In Delaware, DPL earns interest on under-recovered costs and pays interest to customers on over-recovered SOS and GCR costs. In Maryland, DPL does not earn or pay interest to customers on under- or over-recovered SOS costs. The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2017, DPL's regulatory asset of $15 million included $8 million of transmission costs recoverable through its FERC approved formula rate and $7 million of under-recovered electric energy costs. As of December 31, 2017, DPL's regulatory liability of $1 million related to over-recovered electric energy costs. 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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
The ACE energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under ACE’s market-based BGS program and FERC approved transmission rates. ACE earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. ACE earns interest on under-recovered and pays interest to customers on over-recovered BGS costs. As of December 31, 2017, ACE's regulatory asset of $26 million included $11 million of transmission costs recoverable through its FERC approved formula rate and $15 million of under-recovered electric energy costs. As of December 31, 2017, ACE's regulatory liability of $3 million related to over-recovered electric energy costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs.
Deferred storm costs. In the MDPSC’s March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. BGE earns a return on this regulatory asset and the original recovery period of five years was extended for an additional 25 months, in accordance with the MDPSC 2014 electric and natural gas distribution rate case order. This regulatory asset has now been fully amortized as of December 31, 2017.
For Pepco, DPL and ACE, amounts represent total incremental storm restoration costs incurred for repair work due to major storm events in 2017, 2016, 2015, 2012 and 2011 recoverable from customers in the Maryland and New Jersey jurisdictions. These incremental storm restoration costs are amortized over a three or five year period dependent on jurisdiction.
Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion of this regulatory asset that does not earn a regulated rate of return was $9 million as of December 31, 2016. This regulatory asset has now been fully amortized as of December 31, 2017.
Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2017 and 2016, BGE recovered $7 million and $81 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007. This regulatory asset has now been fully amortized as of December 31, 2017.
Energy efficiency and demand response programs. For ComEd, these amounts represent over recoveries related to ComEd’s ICC-approved Energy Efficiency and Demand Response Plan under
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
the energy efficiency rate rider cancelled on June 2, 2017. ComEd expects to refund these over recoveries in future rates. ComEd earns a return on the capital investment incurred under the program, but does not earn or pay a return or interest on under or over recoveries, respectively. For PECO, these amounts represent over recoveries of program costs related to both Phase II and Phase III of its PAPUC-approved EE&C Plan. PECO began recovering the costs of its Phase II and Phase III EE&C Plans through a surcharge in June 2013 and June 2016, respectively, based on projected spending under the programs. Phase II of the program began on June 1, 2013 and expired on May 31, 2016. Phase III of the program began on June 1, 2016 and will expire on May 31, 2021. PECO earns a return on the capital portion of the EE&C Plan. For BGE, these amounts represent under (over) recoveries related to BGE’s Smart Energy Savers Program®, which includes both MDPSC-approved demand response and energy efficiency programs. For the BGE Peak RewardsSMdemand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which began in July 2013 and are being recovered through the surcharge. Actual costs incurred in the energy efficiency program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.
For Pepco, DPL and ACE, amounts represent recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. Pepco Maryland and DPL Maryland energy efficiency program costs are recovered over 5 years and the direct load control program costs are recovered over 5 years and 15 years, depending on the type. ACE costs are recovered over 10 years. Pepco, DPL and ACE earn a return on these regulatory assets.
Merger integration costs. These amounts include integration costs to achieve distribution synergies related to the Constellation merger transaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recover the remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset.
These amounts also include integration costs to achieve distribution synergies related to the PHI acquisition. As of December 31, 2017 and 2016, BGE's regulatory asset of $6 million and $10 million, respectively, included $4 million and $6 million, respectively, of previously incurred PHI integration costs as authorized by the June 2016 rate case order. As of December 31, 2017, Pepco’s regulatory asset of $20 million represents previously incurred PHI integration costs, including $11 million authorized for recovery in Maryland and $9 million expected to be recovered in the District of Columbia service territory. As of December 31, 2016, Pepco's regulatory asset of $11 million represents previously incurred PHI integration costs authorized for recovery in Maryland. As of December 31, 2017, DPL’s regulatory asset of $10 million represents previously incurred PHI integration costs, including $4 million authorized for recovery in Maryland, $5 million authorized for recovery in Delaware electric rates, and $1 million expected to be recovered in electric and gas rates in the Maryland and Delaware service territories. As of December 31, 2016, DPL's regulatory asset of $4 million represents previously incurred PHI integration costs expected to be recovered in the Maryland service territory. As of December 31, 2017, ACE’s regulatory asset of $9 million represents previously incurred PHI integration costs expected to be recovered in the New Jersey service territory. Pepco and DPL are earning a return on the regulatory
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
assets being recovered in Maryland and these costs are being amortized over five years. DPL is earning a return on the regulatory asset being recovered in Delaware and the cost is being amortized over five years. Amounts deferred for Pepco in the District of Columbia and ACE in New Jersey do not earn a return.
Under (Over)-recovered electric and gas revenue decoupling. For BGE, these amounts represent the electric and gas distribution costs recoverable from or (refundable) to customers under BGE’s decoupling mechanisms and are being recovered over the life of the associated assets. As of December 31, 2017, BGE had a regulatory asset of $10 million related to under-recovered electric revenue decoupling and $4 million related to under-recovered natural gas revenue decoupling. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling.
For Pepco and DPL, these amounts represent the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism. Pepco and DPL earn a return on these regulatory assets.
COPCO acquisition adjustment. On July 19, 2007, the MDPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. In February 2017 the MDPSC ruled that the remaining amortization be extended for an additional three years, and this item is now amortized from August 2007 through February 2020. DPL earns a return on these regulatory assets.
Workers compensation and long-term disability costs. These amounts represent accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. The recovery period for these regulatory assets is over the life of the associated assets.
Vacation accrual. These amounts represent accrued vacation costs for PECO, DPL and ACE. PECO, DPL and ACE and the costs are recoverable from customers when actual payments are made to employees or when vacation is taken.
Securitized stranded costs. These amounts represent certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator and costs associated with the regulated operations of ACE’s electricity generation business that are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) to securitize the recoverability of these stranded costs. These bonds mature between 2018 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.
CAP arrearage. These amounts represent the guaranteed recovery of PECO's previously incurred bad debt expense associated with the eligible CAP accounts receivable balances under the IPAF Program as provided by the 2015 electric distribution rate case settlement. These costs are amortized as recovery is received through a combination of customer payments over the duration of the five-year payment agreement term and rate recovery, including through future rate cases if necessary.
Removal costs. These amounts represent funds ComEd, BGE, PHI, Pepco, DPL and ACE have received from customers through depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability is reduced as costs are incurred. PHI, Pepco, DPL, and ACE have a regulatory asset which represents removal costs incurred in excess of amounts received from customers through depreciation rates recoverable from ratepayers. The recovery period of these regulatory assets is over the life of the associated assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DC PLUG charge. On November 9, 2017, the DCPSC issued an order approving the First Biennial Plan and the application for a financing order. As a result, Pepco's obligation of $187 million will be recovered from customers and therefore, a $187 million regulatory asset was established. Pepco will recover $60 million over a two-year period and the remainder will be recovered based on future biennial plans filed with the DCPSC. In addition, $3 million of previously deferred costs from the first Triennial Plan were approved for recovery from customers over a one year recovery period.
Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated future decommissioning costs at the time of decommissioning. See Note 15 — Asset Retirement Obligations for additional information.
Deferred rent. Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease. The costs of the lease are recoverable through the ratemaking process at Pepco, DPL and ACE.
DLC program costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the DLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining useful life of the assets.
Electric distribution tax repairs. PECO’s 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. PECO's 2015 electric distribution rate case settlement requires PECO to pay interest on the unamortized balance of the tax-effected catch-up deduction beginning January 1, 2016.
Gas distribution tax repairs. PECO’s 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits began being reflected in customer bills on January 1, 2013. No interest will be paid to customers.
Renewable portfolio standards costs. Beginning June 1, 2017, ComEd recovers all costs associated with purchasing renewable energy credits through a new tariff rate rider that provides for a reconciliation and true-up to actual costs, with any difference to be credited to or collected from ComEd's retail customers in subsequent periods with interest. In addition, this balance includes the over recovery of renewable energy credits associated with RPS alternative compliance payments recovered under supply base rates. These collections were required under the Illinois Public Utilities Act to be used for renewable energy purchases in accordance with ICC procurement orders. The amortization period is in accordance with the applicable ICC procurement orders.
Zero emission credit costs. Beginning June 1, 2017, ComEd recovers all costs associated with purchasing ZECs through a new tariff rate rider that provides for an annual reconciliation and true-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 with interest.
Over-recovered uncollectible accounts. These amounts represent the difference between ACE's annual uncollectible accounts expense and revenues collected in rates through an NJBPU-approved
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
rider. The difference between GAAP uncollectible expense and revenues collected through the rider each calendar year is recovered or refunded over a twelve-month period beginning in June of the following calendar year.
Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The 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 our Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
| Exelon | | ComEd(a) | | PECO | | BGE(b) | | PHI | | Pepco(c) | | DPL(c) | | ACE |
December 31, 2017 | $ | 69 |
| | $ | 6 |
| | $ | — |
| | $ | 53 |
| | $ | 10 |
| | $ | 6 |
| | $ | 4 |
| | $ | — |
|
| | | | | | | | | | | | | | | |
December 31, 2016 | $ | 72 |
| | $ | 5 |
| | $ | — |
| | $ | 57 |
| | $ | 10 |
| | $ | 6 |
| | $ | 4 |
| | $ | — |
|
__________
| |
(a) | Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets. |
| |
(b) | BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs |
| |
(c) | Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 primarily to recover 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 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 December 31, 2017 and December 31, 2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
As of December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Purchased receivables | $ | 298 |
| | $ | 87 |
| | $ | 70 |
| | $ | 58 |
| | $ | 83 |
| | $ | 56 |
| | $ | 9 |
| | $ | 18 |
|
Allowance for uncollectible accounts (a) | (31 | ) | | (14 | ) | | (5 | ) | | (3 | ) | | (9 | ) | | (5 | ) | | (1 | ) | | (3 | ) |
Purchased receivables, net | $ | 267 |
| | $ | 73 |
| | $ | 65 |
| | $ | 55 |
|
| $ | 74 |
|
| $ | 51 |
|
| $ | 8 |
|
| $ | 15 |
|
| | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
As of December 31, 2016 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Purchased receivables | $ | 313 |
| | $ | 87 |
| | $ | 72 |
| | $ | 59 |
| | $ | 95 |
| | $ | 63 |
| | $ | 10 |
| | $ | 22 |
|
Allowance for uncollectible accounts (a) | (37 | ) | | (14 | ) | | (6 | ) | | (4 | ) | | (13 | ) | | (7 | ) | | (2 | ) | | (4 | ) |
Purchased receivables, net | $ | 276 |
| | $ | 73 |
| | $ | 66 |
| | $ | 55 |
|
| $ | 82 |
|
| $ | 56 |
|
| $ | 8 |
|
| $ | 18 |
|
__________
| |
(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. |
4.5. Mergers, Acquisitions and Dispositions (Exelon, Generation PHI, Pepco and DPL)PHI)
Acquisition of FirstEnergy Solutions Load Business (Exelon and Generation)
On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy). Pursuant to the Purchase Agreement, FirstEnergy agreed to assign all of its retail electricity and wholesale load serving contracts and certain other related commodity contracts to Generation for an all cash purchase price of $140 million. The closing of the transaction was subject to certain conditions including the approval of the Purchase Agreement by the United States Bankruptcy Court for the Northern District of Ohio (Bankruptcy Court). At FirstEnergy's request, Bankruptcy Court's review of the transaction was delayed on six occasions, and Generation disputed these delays with the Bankruptcy Court. On January 23, 2019 the Bankruptcy Court approved an order that stipulated FirstEnergy's termination of the Purchase Agreement, effective January 22, 2019. The termination order provided for Generation to receive a refund of its escrow deposit, payment of a termination fee and reimbursement of transaction expenses, all of which were immaterial.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the 842 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost reimbursement to and on behalf of Entergy of $179 million. As part of the acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have avoided had it shut downshutdown 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. In 2017, the final purchase price consideration of $289 million (including $235 million of cash and $54 million of nuclear fuel) was remitted to and on behalf of Entergy.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 in the first quarter of 2017 to determine the fair value of the FitzPatrick assets acquired and liabilities assumed were preliminary. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date.
During the third quarter of 2017, certain modifications were made to the initial preliminary valuation amounts for acquired property, plant and equipment, the decommissioning ARO, pension and OPEB obligations and related deferred tax liabilities, resulting in a $3 million net increase in assets acquired and liabilities assumed. Additionally, in the third quarter a purchase price settlement payment of $4 million was received from Entergy. These resulted in an adjustment to the after-tax bargain purchase gain recorded at Generation. For the year ended December 31, 2017, theAn after-tax bargain purchase gain of $233 million iswas included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income andwhich primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. There are no further adjustments expected to be made to the allocation of the purchase price. See Note 15 -— Asset Retirement Obligations and Note 16 -— Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick acquisition by Generation as of December 31, 2017:Generation:
|
| | | | |
Cash paid for purchase price | | $ | 110 |
|
Cash paid for net cost reimbursement | | 125 |
|
Nuclear fuel transfer | | 54 |
|
Total consideration transferred | | $ | 289 |
|
| | |
Identifiable assets acquired and liabilities assumed | | |
Current assets | | $ | 60 |
|
Property, plant and equipment | | 298 |
|
Nuclear decommissioning trust funds | | 807 |
|
Other assets(a) | | 114 |
|
Total assets | | $ | 1,279 |
|
| | |
Current liabilities | | $ | 6 |
|
Nuclear decommissioning ARO | | 444 |
|
Pension and OPEB obligations | | 33 |
|
Deferred income taxes | | 149 |
|
Spent nuclear fuel obligation | | 110 |
|
Other liabilities | | 15 |
|
Total liabilities | | $ | 757 |
|
Total net identifiable assets, at fair value | | $ | 522 |
|
| | |
Bargain purchase gain (after-tax) | | $ | 233 |
|
_________
| |
(a) | Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated with the DOE one-time fee obligation. See Note 23-Commitments22-Commitments and Contingencies for additional backgroundinformation regarding SNF obligations to the DOE. |
For the year ended December 31, 2017, Exelon and Generation incurred $57 million of merger and integration related costs to FitzPatrick for the year ended December 31, 2017 which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Exelon and Generation did not incur any merger and integration costs related to FitzPatrick for the year ended December 31, 2018.
Acquisition of ConEdison Solutions (Exelon and Generation)
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.
The fair valuespurchase price 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. The purchase price$257 million equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date. The purchase price allocation is now final.
The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation:
|
| | | | |
Total consideration transferred | | $ | 257 |
|
| | |
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 |
|
Total assets | | $ | 322 |
|
| | |
Mark-to-market derivative liabilities | | $ | 65 |
|
Total liabilities | | $ | 65 |
|
Total net identifiable assets, at fair value | | $ | 257 |
|
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)., for a total purchase price consideration of approximately $7.1 billion. As a result of thatthe 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, requires allocation of merger benefits proportionally across all the jurisdictions.
During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a totalTotal nominal cost of commitments ofwas $513 million excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
generation commitments and charitable contributions). These filings reflected agreements reached with certain parties to the merger proceedings in these jurisdictions. In 2016, the DPSC and NJBPU approved the amounts and allocations of the additional merger benefits for Delaware and New Jersey, respectively. On April 12, 2017, the MDPSC issued an order approving the amounts of the additional merger benefits for Maryland, but amending the proposed allocations of 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.
During the secondfourth quarter of 2017,2018, Exelon finalized the application of $8$5 million funding for low-residential and moderate-incomenon-residential customers in the Pepco Maryland and DPL Maryland service territories.territory. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate Pepco, and DPL. Exelon Corporate recorded a decrease of $5 million and DPL recorded an increase of $8$5 million and Pepco and DPL recorded a decrease of $6 million and $2 million, respectively, in Operating and maintenance expense.
The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the acquisitionmerger date:
| | | Expected Payment Period | | | | | | | | Successor | | | Expected Payment Period | | | | Successor | | | | | | |
Description | | Pepco | | DPL | | ACE | | PHI | | Exelon | | Exelon | | PHI | | Pepco | | DPL | | ACE |
Rate credits | 2016 - 2017 | | $ | 91 |
| | $ | 67 |
| | $ | 101 |
| | $ | 259 |
| | $ | 259 |
| 2016 - 2021 | | $ | 259 |
| | $ | 264 |
| | $ | 91 |
| | $ | 72 |
| | $ | 101 |
|
Energy efficiency | 2016 - 2021 | | — |
| | — |
| | — |
| | — |
| | 122 |
| 2016 - 2021 | | 117 |
| | — |
| | — |
| | — |
| | — |
|
Charitable contributions | 2016 - 2026 | | 28 |
| | 12 |
| | 10 |
| | 50 |
| | 50 |
| 2016 - 2026 | | 50 |
| | 50 |
| | 28 |
| | 12 |
| | 10 |
|
Delivery system modernization | Q2 2017 | | — |
| | — |
| | — |
| | — |
| | 22 |
| Q2 2017 | | 22 |
| | — |
| | — |
| | — |
| | — |
|
Green sustainability fund | Q2 2017 | | — |
| | — |
| | — |
| | — |
| | 14 |
| Q2 2017 | | 14 |
| | — |
| | — |
| | — |
| | — |
|
Workforce development | 2016 - 2020 | | — |
| | — |
| | — |
| | — |
| | 17 |
| 2016 - 2020 | | 17 |
| | — |
| | — |
| | — |
| | — |
|
Other | | 1 |
| | 5 |
| | — |
| | 6 |
| | 29 |
| | 29 |
| | 6 |
| | 1 |
| | 5 |
| | — |
|
Total | | $ | 120 |
| | $ | 84 |
| | $ | 111 |
| | $ | 315 |
| | $ | 513 |
| |
Total commitments | | | $ | 508 |
| | $ | 320 |
| | $ | 120 |
| | $ | 89 |
| | $ | 111 |
|
Remaining commitments as of December 31, 2018 | | | $ | 128 |
| | $ | 92 |
| | $ | 73 |
| | $ | 12 |
| | $ | 7 |
|
Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia and Delaware, 27 MWsat an estimated cost of which are expected to be completed by 2018. These investments are expected to total approximately $137$127 million, are expected to be primarily capital in nature, andwhich will generate future earnings at Exelon and Generation. Investment costs, which are expected to be
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
primarily capital in nature, will be recognized as incurred and recorded on Exelon's and Generation's financial statements. As of December 31, 2018, 27 MWs were developed and Exelon and Generation have incurred costs of $83 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM,PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards,standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and to maintaindid not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and promote energy efficiencyresulted in a proposed REC purchase agreement that is pending review and demand response programsapproval with the DPSC. The third and final 40 MW wind REC tranche will be conducted in the PHI jurisdictions.2022.
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.
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
by the OPC, the Sierra Club, CCAN and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger. The OPC and Sierra Club filed petitions seeking further review in the Maryland Court of Appeals, of Maryland, which is the highest court in Maryland. On June 21, 2017, the Court of Appeals granted discretionary review of the January 27, 2017 decision byAugust 29, 2018, the Maryland Court of Special Appeals. The Maryland Court of Appeals will reviewaffirmed the OPC argument that the MDPSC did not properly consider the acquisition premium paid to PHI shareholders under Maryland’s merger approval standard and the Sierra Club’s argument thatMDPSC's May 2015 Order approving the merger would harm the renewableof Exelon and distributed generation markets. The two lower courts examining these issues rejected these arguments, which Exelon believes are without merit. All briefs have been filed and oral arguments were presented to the court on October 10, 2017.PHI.
Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District Legal Entity of Columbia Office of People’s Counsel, 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 July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.
Accounting for the Merger 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 |
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016) | | $ | 6,933 |
|
Cash paid for PHI preferred stock | | 180 |
|
Cash paid for PHI stock-based compensation equity awards(a) | | 29 |
|
Total purchase price | | $ | 7,142 |
|
__________
| |
(a) | 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 the purchase price allocation in the first quarter of 2017 and the purchase price allocation is now final.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 follows:
|
| | | |
Purchase Price Allocation(a) | |
Current assets | $ | 1,441 |
|
Property, plant and equipment | 11,088 |
|
Regulatory assets | 5,015 |
|
Other assets | 248 |
|
Goodwill | 4,005 |
|
Total assets | $ | 21,797 |
|
| |
Current liabilities | $ | 2,752 |
|
Unamortized energy contracts | 1,515 |
|
Regulatory liabilities | 297 |
|
Long-term debt, including current maturities | 5,636 |
|
Deferred income taxes | 3,447 |
|
Pension and OPEB obligations | 821 |
|
Other liabilities | 187 |
|
Total liabilities | $ | 14,655 |
|
Total purchase price | $ | 7,142 |
|
__________
| |
(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 totalapproximately $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.
billion. The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0$4 billion, which was recognized as goodwill by PHI and Exelon at the acquisitionmerger date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. None of this goodwill is expected to be tax deductible. For purposes of future required impairment assessments, the goodwill has been assigned to PHI's reportable units Pepco, DPL and ACE 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.ACE. See Note 10 - Intangible Assets for additional information.
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.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 3 - 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 December 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 reflecting out-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 Purchased 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.
As mentioned, under cost-of-service rate regulation, ratesRates 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 $4,829 million and Net income of $364 million during the year ended December 31, 2017, and Operating revenues of $3,785 million and Net loss of $(66) million for the year ended December 31, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The current impact of PHI, including its unregulated businesses, in Exelon's Consolidated Statements of Operations and Comprehensive Income includes Operating revenues and Net Income (Loss) as follows:
|
| | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating Revenues | 4,670 |
| | 4,829 |
| | 3,785 |
|
Net Income (Loss) | 453 |
| | 364 |
| | (66 | ) |
For the periods ended December 31, 2018, 2017 and 2016, the Registrants have recognized costs to achieve the PHI acquisitionmerger as follows:
| | | For the Year Ended December 31, | For the Year Ended December 31, |
Acquisition, Integration and Financing Costs(a) | 2017 | | 2016 | 2018 | | 2017 | | 2016 |
Exelon | $ | 16 |
| | $ | 143 |
| $ | 7 |
| | $ | 16 |
| | $ | 143 |
|
Generation | 22 |
| | 37 |
| 5 |
| | 22 |
| | 37 |
|
ComEd(b) | 1 |
| | (6 | ) | — |
| | 1 |
| | (6 | ) |
PECO | 4 |
| | 5 |
| 1 |
| | 4 |
| | 5 |
|
BGE(b) | 4 |
| | (1 | ) | 1 |
| | 4 |
| | (1 | ) |
Pepco(b) | (6 | ) | | 28 |
| — |
| | (6 | ) | | 28 |
|
DPL(b) | (7 | ) | | 20 |
| — |
| | (7 | ) | | 20 |
|
ACE(b) | (6 | ) | | 19 |
| — |
| | (6 | ) | | 19 |
|
| | | | | | | | | | Successor | | | Predecessor |
| Successor | | | Predecessor | For the Year Ended December 31, | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Acquisition, Integration and Financing Costs(a) | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | 2018 | | 2017 | | |
PHI(b) | $ | (18 | ) | | $ | 69 |
| | | $ | 29 |
| $ | — |
| | $ | (18 | ) | | $ | 69 |
| | | $ | 29 |
|
______________
| |
(a) | The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above. |
| |
(b) | For the year ended December 31, 2017, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisitionas regulatory assets of $24 million, $8 million, $8 million, and $8 million incurred at PHI, Pepco, DPL and ACE, respectively, that have been recorded as a regulatory asset for anticipated recovery.respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisitionas regulatory assets of $8 million, $6 million, $11 million and $4 million incurred at ComEd, BGE, Pepco and DPL, respectively, that have been recorded as a regulatory asset for anticipated recovery.respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs to achieve distribution synergies related to the PHI acquisitionas regulatory assets of $16 million incurred at PHI that have been recorded as a regulatory asset for anticipated recovery.PHI. See Note 34 - Regulatory Matters for moreadditional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pro-forma Impact of the Merger
The following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the PHI merger 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.
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.
|
| | | | | | | |
| Year Ended December 31, |
| 2016(a) | | 2015(b) |
Total operating revenues | $ | 32,342 |
| | $ | 33,823 |
|
Net income attributable to common shareholders | 1,562 |
| | 2,618 |
|
| | | |
Basic earnings per share | $ | 1.69 |
| | $ | 2.85 |
|
Diluted earnings per share | 1.69 |
| | 2.84 |
|
______________
| |
(a) | The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016. |
| |
(b) | The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015. |
Asset DispositionsDisposition of Oyster Creek (Exelon and Generation)
On July 31, 2018, Generation PHI, Pepcoentered into an agreement with Holtec International (Holtec) and DPL)its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of the Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.
Under the terms of the transaction, Generation will transfer to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.
As a result of the transaction, in 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. At December 31, 2018 Generation has $897 million and $777 million of Assets held for sale and Liabilities held for sale, respectively, for Oyster Creek. Upon remeasurement of the Oyster Creek ARO in 2018, Exelon and Generation recognized an $84 million pre-tax charge to Operating and maintenance expense. See Note 15 -Asset Retirement Obligations for additional information.
Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the closing conditions to occur in the second half of 2019.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)
EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP iswas an indirect wholly owned subsidiary of Exelon and Generation. Each of the aforementioned facilities are 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 secured a nonrecourse senior secured term loan facility, a revolving loan facility and certain commodity and interest rate swaps.
EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. loss. See Note 13 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 7 - Impairment of Long-Lived Assets and Intangibles for furtheradditional information.
On November 7, 2017, EGTP and all of its wholly owned subsidiaries (collectively with EGTP, the "Debtors") filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. The Debtors sought Bankruptcy Court authorization to jointly administer the Chapter 11 cases. The Debtors are continuing to manage their assets and operate their businesses as "debtorsDelaware, which resulted in possession" under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and the orders of the Bankruptcy Court. As a result of the bankruptcy filing, Exelon and Generation deconsolidateddeconsolidating EGTP's
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
assets and liabilities from their consolidated financial statements resultingin the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter 11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP’sEGTP's generating plants, the Handley Generating Station, for approximately $60 million, subject to a potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley Generating Station be consummated through a court-approved and supervised sales process. The acquisition was approved by the Bankruptcy Court in Januaryclosed on April 4, 2018 and the transaction is expected to be completedfor a purchase price of $62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the first halfownership of 2018.EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders.
Other Asset Dispositions (Exelon, Generation, DPL and Pepco)
In December 2017, Pepco Building Services, Inc.Generation entered into a purchase and salean agreement to sell its interest in an electrical contracting business that primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution systems. The closing of the sale is expected to be completed in the first quarter of 2018. As a result, as of December 31, 2017, certain assets and liabilities were classified as held for sale at their respective fair values less costs to sell and included in the Other current assets and Other current liabilities balances onin Exelon's and Generation's Consolidated Balance Sheet. On February 28, 2018, Generation completed the sale of its interest for $87 million, resulting in a pre-tax gain which is included within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
During the fourth quarter of 2016, as part of its continual assessment of growth and development opportunities, Generation reevaluated and in certain instances terminated or renegotiated certain projects and contracts. As a result, a pre-tax loss of $69 million was recorded within Loss on salesales of assets and businesses and pre-tax impairment charges of $23 million was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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. In December 2016, DPL completed the sale of a 48-acre land parcel located in Middletown, DE, resulting in a pre-tax gain of approximately $5 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in Exelon's and PHI'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 13 - Debt and Credit Agreements for moreadditional information. In December 2016, Generation sold substantially all of the Upstream assets for $37 million which resulted in a pre-tax loss on sale of $10 million which is included in Gain (loss) on sales of assets onand businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.
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 Exelon's and PHI's Consolidated Statements of Operations and Comprehensive Income.
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 November 10, 2015, Pepco completed the sale of a 3.5-acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C., resulting in a pre-tax gain of $37 million.
On December 31, 2015, Pepco completed the sale of a 3.8-acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C., resulting in a pre-tax gain of $9 million. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8-acre land parcel.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
5. Accounts Receivable (All Registrants)
Accounts receivable at December 31, 2017 and 2016 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unbilled customer revenues | $ | 1,858 |
| | $ | 1,017 |
| (a) | $ | 242 |
| | $ | 162 |
| | $ | 205 |
| | $ | 232 |
| | $ | 133 |
| | $ | 68 |
| | $ | 31 |
|
Allowance for uncollectible accounts (b) | (322 | ) |
| (114 | ) |
| (73 | ) |
| (56 | ) | (c) | (24 | ) | | (55 | ) | | (21 | ) | | (16 | ) | | (18 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | | |
2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
Unbilled customer revenues | $ | 1,673 |
| | $ | 910 |
| (a) | $ | 219 |
| | $ | 140 |
| | $ | 182 |
| | $ | 222 |
| | $ | 123 |
| | $ | 58 |
| | $ | 41 |
| |
Allowance for uncollectible accounts(b) | (334 | ) |
| (91 | ) |
| (70 | ) |
| (61 | ) | (c) | (32 | ) | | (80 | ) | (d) | (29 | ) | (d) | (24 | ) | (d) | (27 | ) | (d) |
__________
| |
(a) | Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy. |
| |
(b) | Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable. |
| |
(c) | Excludes the non-current allowance for uncollectible accounts of $15 million and $23 million at December 31, 2017 and 2016, respectively, related to PECO’s current installment plan receivables described below. |
| |
(d) | At December 31, 2016, as explained in Note 1 — Significant Accounting Policies, PHI, Pepco, DPL and ACE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in an overall increase of $30 million, $14 million, $8 million, and $8 million in the allowance for uncollectible accounts with $20 million, $8 million, $4 million, and $8 million deferred as a regulatory asset on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets at December 31, 2016, respectively. This also resulted in a $10 million, $6 million, and $4 million pre-tax charge to provision for uncollectible accounts expense for the year ended December 31, 2016, which is included in Operating and maintenance expense on PHI's, Pepco's and DPL's Consolidated Statements of Operations and Comprehensive Income, respectively. |
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 $11 million and $9 million at December 31, 2017 and 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. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2017 of $11 million consists of $3 million and $8 million for medium risk and high-risk segments, respectively. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2016 of $13 million consists of $1 million, $3 million and $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 December 31, 2017 and 2016 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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
and reserved for in accordance with the methodology discussed in Note 1—Significant Accounting Policies.
6. Property, Plant and Equipment (All Registrants)
Exelon
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | |
Electric—transmission and distribution | 5-90 | | $ | 49,506 |
| | $ | 45,698 |
| 5-90 | | $ | 53,090 |
| | $ | 49,506 |
|
Electric—generation | 2-56 | | 29,019 |
| | 27,193 |
| 1-56 | | 29,170 |
| | 29,019 |
|
Gas—transportation and distribution | 5-90 | | 5,050 |
| | 4,642 |
| 5-90 | | 5,530 |
| | 5,050 |
|
Common—electric and gas | 5-75 | | 1,447 |
| | 1,312 |
| 5-75 | | 1,627 |
| | 1,447 |
|
Nuclear fuel (a) | 1-8 | | 6,420 |
| | 6,546 |
| 1-8 | | 5,957 |
| | 6,420 |
|
Construction work in progress | N/A | | 2,825 |
| | 4,306 |
| N/A | | 3,377 |
| | 2,825 |
|
Other property, plant and equipment (b) | 2-50 | | 999 |
| | 1,027 |
| 1-50 | | 858 |
| | 999 |
|
Total property, plant and equipment | | 95,266 |
| | 90,724 |
| | 99,609 |
| | 95,266 |
|
Less: accumulated depreciation (c) | | 21,064 |
| | 19,169 |
| | 22,902 |
| | 21,064 |
|
Property, plant and equipment, net | | $ | 74,202 |
| | $ | 71,555 |
| | $ | 76,707 |
| | $ | 74,202 |
|
__________
| |
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,196$1,004 million and $1,326$1,196 million at December 31, 20172018 and 2016,2017, respectively. |
| |
(b) | Includes Generation’s buildings under capital lease with a net carrying value of $7$5 million and $10$7 million at December 31, 20172018 and 2016,2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and $52 million,2017, and total accumulated amortization was $40$42 million and $42$40 million, as of December 31, 20172018 and 2016,2017, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 20172018 and 2016,2017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 20172018 and 2016.2017. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $44$39 million, $21$19 million, $26$25 million, $59$61 million, $15$17 million and $27$28 million, respectively, at December 31, 2017. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $0 million and $17 million as of December 31, 2017 and 2016, respectively. Generation's turbine equipment was impaired by $11 million and the remaining $6 million was moved to the assets held for sale account at December 31, 2017.2018. |
| |
(c) | Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $3,159$2,969 million and $3,186$3,159 million as of December 31, 20172018 and 2016,2017, respectively. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
| | Average Service Life Percentage by Asset Category | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Electric—transmission and distribution | 2.75 | % | | 2.73 | % | | 2.83 | % | 2.73 | % | | 2.75 | % | | 2.73 | % |
Electric—generation(a) | 4.36 | % | (a) | 5.94 | % | (a) | 3.47 | % | 5.37 | % | | 4.36 | % | | 5.94 | % |
Gas | 2.10 | % | | 2.17 | % | | 2.17 | % | 2.07 | % | | 2.10 | % | | 2.17 | % |
Common—electric and gas | 7.05 | % | | 7.41 | % | | 7.79 | % | 6.98 | % | | 7.05 | % | | 7.41 | % |
__________
| |
(a) | See Note 8 — Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | |
Electric—generation | 2-56 | | $ | 29,019 |
| | $ | 27,193 |
| 1-56 | | $ | 29,170 |
| | $ | 29,019 |
|
Nuclear fuel (a) | 1-8 | | 6,420 |
| | 6,546 |
| 1-8 | | 5,957 |
| | 6,420 |
|
Construction work in progress | N/A | | 838 |
| | 2,332 |
| N/A | | 997 |
| | 838 |
|
Other property, plant and equipment (b) | 2-3 | | 57 |
| | 76 |
| 1-8 | | 63 |
| | 57 |
|
Total property, plant and equipment | | 36,334 |
| | 36,147 |
| | 36,187 |
| | 36,334 |
|
Less: accumulated depreciation (c) | | 11,428 |
| | 10,562 |
| | 12,206 |
| | 11,428 |
|
Property, plant and equipment, net | | $ | 24,906 |
| | $ | 25,585 |
| | $ | 23,981 |
| | $ | 24,906 |
|
__________
| |
(a) | Includes nuclear fuel that is in the fabrication and installation phase of $1,196$1,004 million and $1,326$1,196 million at December 31, 20172018 and 2016,2017, respectively. |
| |
(b) | Includes buildings under capital lease with a net carrying value of $7$5 million and $10$7 million at December 31, 20172018 and 2016,2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and $52 million,2017, and total accumulated amortization was $40$42 million and $42$40 million, as of December 31, 2018 and 2017, and 2016, respectively. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $0 million and $17 million as of December 31, 2017 and 2016, respectively. Generation's turbine equipment was impaired by $11 million and the remaining $6 million was moved to the assets held for sale account at December 31, 2017. |
| |
(c) | Includes accumulated amortization of nuclear fuel in the reactor core of $3,159$2,969 million and $3,186$3,159 million as of December 31, 20172018 and 2016,2017, respectively. |
The annual depreciation provisions as a percentage of average service life for electric generation assets were 4.36%5.37%, 5.94%4.36% and 3.47%5.94% for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. See Note 8 — Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.
License Renewals
Generation’s depreciationDepreciation provisions are based on the estimated useful lives of its generatingthe stations, which reflect the actual renewal of the operating licenses for all of Generation's operating nuclear generating stations (exceptexcept for Oyster Creek, ClintonTMI and TMI) and the hydroelectric generating stations.Clinton. As a result, the receipt of license renewals has no material impact onin the Consolidated Statements of Operations and Comprehensive Income. Clinton depreciation provisions are based on 2027 which is the last year of the Illinois ZECs. InBeginning in 2017, TMI and Oyster Creek and TMI depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions will bewere based on its announced shutdown date of September 2018. Clinton depreciation provisions are based on an estimated useful life through 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 34 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs. SeeZECs and Note 8 — Early Nuclear Plant Retirements for additional information on the impacts of expected and potential early plant retirement.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | |
Electric—transmission and distribution | 5-80 | | $ | 24,423 |
| | $ | 22,636 |
| 5-80 | | $ | 25,991 |
| | $ | 24,423 |
|
Construction work in progress | N/A | | 517 |
| | 569 |
| N/A | | 705 |
| | 517 |
|
Other property, plant and equipment (a), (b) | 36-50 | | 52 |
| | 67 |
| 35-50 | | 46 |
| | 52 |
|
Total property, plant and equipment | | 24,992 |
| | 23,272 |
| | 26,742 |
| | 24,992 |
|
Less: accumulated depreciation | | 4,269 |
| | 3,937 |
| | 4,684 |
| | 4,269 |
|
Property, plant and equipment, net | | $ | 20,723 |
| | $ | 19,335 |
| | $ | 22,058 |
| | $ | 20,723 |
|
__________
| |
(a) | Includes buildings under capital lease with a net carrying value at both December 31, 20172018 and 20162017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 20172018 and 2016.2017. |
| |
(b) | IncludesRepresents land held for future use and non-utility property. |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.99%2.95%, 3.03%2.99% and 3.03% for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively.
PECO
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | |
Electric—transmission and distribution | 5-65 | | $ | 7,975 |
| | $ | 7,591 |
| 5-65 | | $ | 8,359 |
| | $ | 7,975 |
|
Gas—transportation and distribution | 5-70 | | 2,504 |
| | 2,348 |
| 5-70 | | 2,694 |
| | 2,504 |
|
Common—electric and gas | 5-50 | | 710 |
| | 670 |
| 5-50 | | 756 |
| | 710 |
|
Construction work in progress | N/A | | 254 |
| | 188 |
| N/A | | 343 |
| | 254 |
|
Other property, plant and equipment (a) | 50 | | 21 |
| | 21 |
| 50 | | 19 |
| | 21 |
|
Total property, plant and equipment | | 11,464 |
| | 10,818 |
| | 12,171 |
| | 11,464 |
|
Less: accumulated depreciation | | 3,411 |
| | 3,253 |
| | 3,561 |
| | 3,411 |
|
Property, plant and equipment, net | | $ | 8,053 |
| | $ | 7,565 |
| | $ | 8,610 |
| | $ | 8,053 |
|
__________
| |
(a) | Represents land held for future use and non-utility property. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
|
| | | | | | | | |
Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
Electric—transmission and distribution | 2.35 | % | | 2.37 | % | | 2.32 | % |
Gas | 1.90 | % | | 1.89 | % | | 1.82 | % |
Common—electric and gas | 5.44 | % | | 5.47 | % | | 5.11 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
|
| | | | | | | | | |
| Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-90 | | $ | 7,951 |
| | $ | 7,464 |
|
Gas—distribution | 5-90 | | 2,630 |
| | 2,379 |
|
Common—electric and gas | 5-40 | | 860 |
| | 771 |
|
Construction work in progress | N/A | | 410 |
| | 367 |
|
Other property, plant and equipment (a) | 20 | | 25 |
| | 26 |
|
Total property, plant and equipment | | | 11,876 |
| | 11,007 |
|
Less: accumulated depreciation | | | 3,633 |
| | 3,405 |
|
Property, plant and equipment, net | | | $ | 8,243 |
| | $ | 7,602 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
|
| | | | | | | | |
Average Service Life Percentage by Asset Category | 2018 | | 2017 | | 2016 |
Electric—transmission and distribution | 2.61 | % | | 2.58 | % | | 2.56 | % |
Gas | 2.36 | % | | 2.33 | % | | 2.45 | % |
Common—electric and gas | 8.50 | % | | 8.64 | % | | 9.45 | % |
PHI
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
|
| | | | | | | | | |
| Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-75 | | $ | 12,664 |
| | $ | 11,517 |
|
Gas—distribution | 5-75 | | 486 |
| | 449 |
|
Common—electric and gas | 5-75 | | 126 |
| | 82 |
|
Construction work in progress | N/A | | 912 |
| | 835 |
|
Other property, plant and equipment (a) | 3-43 | | 99 |
| | 102 |
|
Total property, plant and equipment | | | 14,287 |
|
| 12,985 |
|
Less: accumulated depreciation | | | 841 |
| | 487 |
|
Property, plant and equipment, net | | | $ | 13,446 |
|
| $ | 12,498 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
|
| | | | | | | | |
Average Service Life Percentage by Asset Category | 2017 | | 2016 | | 2015 |
Electric—transmission and distribution | 2.37 | % | | 2.32 | % | | 2.39 | % |
Gas | 1.89 | % | | 1.82 | % | | 1.87 | % |
Common—electric and gas | 5.47 | % | | 5.11 | % | | 5.16 | % |
BGE
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2017 and 2016:
|
| | | | | | | | | |
| Average Service Life (years) | | 2017 | | 2016 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-90 | | $ | 7,464 |
| | $ | 7,067 |
|
Gas—distribution | 5-90 | | 2,379 |
| | 2,170 |
|
Common—electric and gas | 5-40 | | 771 |
| | 707 |
|
Construction work in progress | N/A | | 367 |
| | 318 |
|
Other property, plant and equipment (a) | 20 | | 26 |
| | 32 |
|
Total property, plant and equipment | | | 11,007 |
| | 10,294 |
|
Less: accumulated depreciation | | | 3,405 |
| | 3,254 |
|
Property, plant and equipment, net | | | $ | 7,602 |
| | $ | 7,040 |
|
__________
| |
(a) | Represents land held for future use and non-utility property. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
|
| | | | | | | | |
Average Service Life Percentage by Asset Category | 2017 | | 2016 | | 2015 |
Electric—transmission and distribution | 2.58 | % | | 2.56 | % | | 2.62 | % |
Gas | 2.33 | % | | 2.45 | % | | 2.50 | % |
Common—electric and gas | 8.64 | % | | 9.45 | % | | 10.35 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2017 and 2016:
|
| | | | | | | | | | |
| | | Successor |
| Average Service Life (years) | | 2017 | | 2016 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-75 | | $ | 11,517 |
| | $ | 10,315 |
|
Gas—distribution | 5-75 | | 449 |
| | 414 |
|
Common—electric and gas | 5-75 | | 82 |
| | 65 |
|
Construction work in progress | N/A | | 835 |
| | 892 |
|
Other property, plant and equipment (a) | 3-43 | | 102 |
| | 107 |
|
Total property, plant and equipment | | | 12,985 |
|
|
| 11,793 |
|
Less: accumulated depreciation | | | 487 |
| — |
| 195 |
|
Property, plant and equipment, net | | | $ | 12,498 |
|
|
| $ | 11,598 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
| | Average Service Life Percentage by Asset Category | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Electric—transmission and distribution | 2.63 | % | | 2.52 | % | | 2.48 | % | 2.61 | % | | 2.63 | % | | 2.52 | % |
Gas | 2.07 | % | | 2.57 | % | | 2.55 | % | 1.59 | % | | 2.07 | % | | 2.57 | % |
Common—electric and gas | 6.50 | % | | 8.12 | % | | 5.19 | % | 6.30 | % | | 6.50 | % | | 8.12 | % |
Pepco
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | | | |
Electric—transmission and distribution | 5-75 | | $ | 8,646 |
| | $ | 8,018 |
| 5-75 | | $ | 9,217 |
| | $ | 8,646 |
|
Construction work in progress | N/A | | 473 |
| | 537 |
| N/A | | 536 |
| | 473 |
|
Other property, plant and equipment (a) | 25-33 | | 59 |
| | 66 |
| 25-33 | | 61 |
| | 59 |
|
Total property, plant and equipment | | 9,178 |
|
|
| 8,621 |
| | 9,814 |
|
| 9,178 |
|
Less: accumulated depreciation | | 3,177 |
| — |
| 3,050 |
| | 3,354 |
| | 3,177 |
|
Property, plant and equipment, net | | $ | 6,001 |
|
|
| $ | 5,571 |
| | $ | 6,460 |
|
| $ | 6,001 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. Utility |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.40%, 2.35% and 2.17% for the years ended December 31, 2018, 2017 and 2016, respectively.
DPL
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:
|
| | | | | | | | | |
| Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-70 | | $ | 4,195 |
| | $ | 3,875 |
|
Gas—distribution | 5-75 | | 651 |
| | 614 |
|
Common—electric and gas | 5-75 | | 136 |
| | 117 |
|
Construction work in progress | N/A | | 151 |
| | 205 |
|
Other property, plant and equipment (a) | 10-43 | | 17 |
| | 15 |
|
Total property, plant and equipment | | | 5,150 |
|
| 4,826 |
|
Less: accumulated depreciation | | | 1,329 |
| | 1,247 |
|
Property, plant and equipment, net | | | $ | 3,821 |
|
| $ | 3,579 |
|
__________
| |
(a) | Represents plant is generally subject to a first mortgage lien.held for future use and non-utility property. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.35%, 2.17% and 2.13% for the years ended December 31, 2017, 2016 and 2015, respectively.
DPL
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2017 and 2016:
|
| | | | | | | | | | |
| Average Service Life (years) | | 2017 | | 2016 |
Asset Category | | | | | |
Electric—transmission and distribution | 5-70 | | $ | 3,875 |
| | $ | 3,574 |
|
Gas—distribution | 5-75 | | 614 |
| | 580 |
|
Common—electric and gas | 5-75 | | 117 |
| | 115 |
|
Construction work in progress | N/A | | 205 |
| | 163 |
|
Other property, plant and equipment (a) | 10-43 | | 15 |
| | 16 |
|
Total property, plant and equipment | | | 4,826 |
|
|
| 4,448 |
|
Less: accumulated depreciation | | | 1,247 |
| — |
| 1,175 |
|
Property, plant and equipment, net | | | $ | 3,579 |
|
|
| $ | 3,273 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien. |
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
| | Average Service Life Percentage by Asset Category | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Electric—transmission and distribution | 2.75 | % | | 2.49 | % | | 2.44 | % | 2.77 | % | | 2.75 | % | | 2.49 | % |
Gas | 2.07 | % | | 2.57 | % | | 2.55 | % | 1.59 | % | | 2.07 | % | | 2.57 | % |
Common—electric and gas | 4.14 | % | | 4.99 | % | | 4.24 | % | 3.70 | % | | 4.14 | % | | 4.99 | % |
ACE
The following table presents a summary of property, plant and equipment by asset category as of December 31, 20172018 and 2016:2017:
| | | Average Service Life (years) | | 2017 | | 2016 | Average Service Life (years) | | 2018 | | 2017 |
Asset Category | | | | | | | | |
Electric—transmission and distribution | 5-60 | | $ | 3,607 |
| | $ | 3,341 |
| 5-60 | | $ | 3,866 |
| | $ | 3,607 |
|
Construction work in progress | N/A | | 138 |
| | 169 |
| N/A | | 209 |
| | 138 |
|
Other property, plant and equipment (a) | 13-15 | | 27 |
| | 27 |
| 13-15 | | 28 |
| | 27 |
|
Total property, plant and equipment | | 3,772 |
|
|
| 3,537 |
| | 4,103 |
|
| 3,772 |
|
Less: accumulated depreciation | | 1,066 |
| — |
| 1,016 |
| | 1,137 |
| | 1,066 |
|
Property, plant and equipment, net | | $ | 2,706 |
|
|
| $ | 2,521 |
| | $ | 2,966 |
|
| $ | 2,706 |
|
__________
| |
(a) | Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien. |
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45%, 2.46% and 2.45% for the years ended December 31, 2018, 2017 and 2016, respectively.
Capitalized Software Costs (All Registrants)
The following tables presents net unamortized capitalized software costs and amortization of capitalized software costs by year.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net unamortized software costs | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2018 | $ | 810 |
| | $ | 164 |
| | $ | 206 |
| | $ | 98 |
| | $ | 166 |
| | $ | 165 |
| | $ | 26 |
| | $ | 21 |
| | $ | 14 |
|
December 31, 2017 | 834 |
| | 173 |
| | 227 |
| | 111 |
| | 179 |
| | 133 |
| | 2 |
| | 1 |
| | 1 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amortization of capitalized software costs | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
2018 | $ | 282 |
| | $ | 78 |
| | $ | 79 |
| | $ | 37 |
| | $ | 48 |
| | $ | 2 |
| | $ | 2 |
| | $ | 1 |
|
2017 | 270 |
| | 73 |
| | 73 |
| | 39 |
| | 46 |
| | — |
| | — |
| | — |
|
2016 | 255 |
| | 72 |
| | 62 |
| | 33 |
| | 44 |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | For the year ended December 31, 2018 | | For the year ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Amortization of capitalized software costs | $ | 33 |
| | $ | 34 |
| | $ | 29 |
| | | $ | 8 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Capitalized Interest and AFUDC (All Registrants)
The annual depreciation provisions as a percentage of average service life for electric transmissionfollowing table summarizes total incurred interest, capitalized interest and distribution assets were 2.46%, 2.45% and 2.46% for the years ended December 31, 2017, 2016 and 2015, respectively.credits to AFUDC by year:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
2018 | Total incurred interest(a) | $ | 1,695 |
| | $ | 464 |
| | $ | 377 |
| | $ | 141 |
| | $ | 130 |
| | $ | 162 |
| | $ | 62 |
| | $ | 68 |
|
| Capitalized interest | 31 |
| | 31 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 109 |
| | — |
| | 30 |
| | 12 |
| | 24 |
| | 34 |
| | 4 |
| | 4 |
|
2017 | Total incurred interest(a) | $ | 1,658 |
| | $ | 502 |
| | $ | 369 |
| | $ | 130 |
| | $ | 111 |
| | $ | 133 |
| | $ | 54 |
| | $ | 64 |
|
| Capitalized interest | 63 |
| | 63 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 108 |
| | — |
| | 20 |
| | 12 |
| | 22 |
| | 34 |
| | 10 |
| | 9 |
|
2016 | Total incurred interest(a) | $ | 1,678 |
| | $ | 472 |
| | $ | 469 |
| | $ | 127 |
| | $ | 114 |
| | $ | 137 |
| | $ | 52 |
| | $ | 65 |
|
| Capitalized interest | 108 |
| | 107 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Credits to AFUDC debt and equity | 98 |
| | — |
| | 22 |
| | 11 |
| | 30 |
| | 29 |
| | 7 |
| | 9 |
|
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | For the year ended December 31, 2018 | | For the year ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Total incurred interest(a) | $ | 305 |
| | $ | 263 |
| | $ | 207 |
| | | $ | 68 |
|
Credits to AFUDC debt and equity | 44 |
| | 54 |
| | 35 |
| | | 10 |
|
__________
| |
(a) | Includes interest expense to affiliates. |
See Note 1 — Significant Accounting Policies for furtheradditional information regarding property, plant and equipment policies and accounting for capitalized software costs for the Registrants.policies. See Note 13 — Debt and Credit Agreements for furtheradditional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.
7. Impairment of Long-Lived Assets and Intangibles (Exelon, Generation and PHI)
Long-Lived Assets (Exelon, Generation and PHI)
Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. At Generation, EGTP’s operatingIn the second quarter of 2018, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows have been negatively impacted by certain market conditions and fair value of the seasonality ofgroup were less than its cash flows. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sellcarrying value. The fair value analysis was based on the assets of its wholly owned subsidiaries.income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, Exelonlong-lived merchant wind assets held and Generation classified certainused with a net carrying amount of EGTP's assets$41 million were fully impaired and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge of $460$41 million was recorded during 2018 within Operating and maintenance expense on theirin Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income during 2017.Income.
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11March 29, 2018, Generation notified ISO-NE of the United States Code inearly retirement of its Mystic Generating Station's Units 7, 8, 9 and the United States Bankruptcy Court forMystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These events suggested that the Districtcarrying value of Delaware and, asits New England asset group may be impaired. As a result, ExelonGeneration completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and Generation deconsolidated EGTP's assetsno impairment charge was required. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and liabilities from their consolidated financial statements.fuel security could potentially result in future impairments of the New England asset group, which could be material. See Note 48 — Mergers, Acquisitions and Dispositions and Note 13 — Debt and Credit Agreements,Early Plant Retirements for furtheradditional information.
In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property within the District of Columbia and paid the District of Columbia $25 million, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined over time through future negotiations. In the fourth quarter of
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2017, based upon the lack of currently available sponsorship opportunities, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI’s Consolidated Statements of Operations and Comprehensive Income.
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income during 2017. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.
In the second quarter of 2016, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
DuringIn the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its Upstream subsidiary CEU Holdings, LLC (as described in Note 13 — Debt and Credit Agreements) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream natural gas and oil exploration and production business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 13 — Debt and Credit Agreements for additional information. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 45 — Mergers, Acquisitions and Dispositions for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In the second quarter of 2016, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Also in the second quarter of 2016, updates to Exelon'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.
The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.
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).
Pursuant to the applicable authoritative guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other-than-temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments based on the income approach, which uses a discounted cash flow analysis, taking into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements.
All the Headleases were terminated by the second quarter of 2016, and no events occurred prior to the termination that required Exelon to review the estimated residual values of the direct financing lease investments in 2016. 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 14 — Income Taxes for additional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
8. Early Nuclear Plant Retirements (Exelon and Generation)
Exelon and Generation continue tocontinuously evaluate factors that affect 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,including, 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 the benefits they provide through their carbon-free emissions, reliability, or fuel security, 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. The precise timing of an early retirement date for any nuclear plant, and the resulting financial statement impacts, may be affected by a number ofmany 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 trustNDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, and just prior to its next scheduled nuclear refueling outage.
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities Clinton,nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island (TMI) nuclear plantsplant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG has made public similar financial challenges facing its New Jersey nuclear plants including Salem, of which Generation owns a 42.59% ownership interest.
In Illinois, the Clinton and Quad Cities nuclear plants continued to face significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2026 for Clinton and 2032 for Quad Cities). In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price was insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. In May 2016, Quad Cities did not clear in the PJM capacity auction for the 2019-2020 planning year. Based on these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, onOn June 2, 2016, Generation announced it would shut downshutdown the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively.respectively, given a lack of progress on Illinois energy legislation and MISO market reforms, and capacity auctions results that failed to cover cash operating costs and a risk-adjusted rate of return to shareholders.
On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that now provides compensation throughto Clinton and Quad Cities for the procurement of ZECs targeted at preserving the environmentalcarbon-free attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria, much like the solution implemented with the New York CES. The Illinois ZES will have a 10-year duration extending from June 1, 2017their production through May 31, 2027. See Note 3 - Regulatory Matters for additional discussion on the Illinois FEJA and the ZES. With the passage of the Illinois ZES and subject to prevailing over any related potential administrative or legal challenges, in December 2016, Generation reversed its June 2016 decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Clinton and Quad Cities are currently licensed to operate through 2026 and 2032, respectively. See Note 4 - Regulatory Matters for additional information on the Illinois FEJA and the ZES.
In New York, the Ginna and Nine Mile Point nuclear plants continue to face significantfaced similar 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). Onon August 1, 2016, the NYPSC issued an order adopting the CES, which would providenow provides payments to Ginna and Nine Mile Point, as well as FitzPatrick, for the environmental attributes of their production. On November 18, 2016,production through 2029. Ginna and Nine Mile Point executed the necessary contracts with NYSERDA, as required under the CES. SubjectUnit 1 are currently licensed to prevailing over any administrative or legal challenges, the New York CES will allow Ginnaoperate through 2029, and Nine Mile Point to continue to operate at leastUnit 2 through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes is through the end of their current operating licenses. The approved RSSA required Ginna to operate through the RSSA term expiring on March 31, 2017 and required notification to the NYPSC if Ginna did not plan to retire shortly after the expiration of the RSSA. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the expiry
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
of the RSSA. Refer to2046. See Note 34 - Regulatory Matters for additional discussioninformation on the Ginna RSSA and the New York CES.
Assuming the successful implementationcontinued effectiveness of both 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 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 positions.statements.
In Pennsylvania, the TMI nuclear plant did notfailed to clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear in the PJM base residual capacity auction. The plant is currently committed to operate through May 2019auction and is licensed to operate through 2034. Onon May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shut downshutdown the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.
Combined NotesIn 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to Consolidated Financial Statements - (Continued)
(Dollarsavoid significant costs associated with the construction of cooling towers to meet the State's then new environmental regulations. Since then, like other nuclear sites, Oyster Creek continued to face rising operating costs amid a historically low wholesale power price environment. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations in millions, except per share data unless otherwise noted)
September 2018.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized one-time charges in Operating and maintenance expense related to materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments, among other items. In addition to these one-time charges, annual incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions were also recorded. See Note 15 — Asset Retirement Obligations for additional detailinformation on changes to the nuclear decommissioning ARO balances.balance. The total annual impact of these charges by year are summarized in the table below.
| | Income statement expense (pre-tax) | | 2017(a) | | 2016(b) | | 2018(a) | | 2017(b) | | 2016(c) |
Depreciation and Amortization | | | | | | | | | | |
Accelerated depreciation(c)(d) | | $ | 250 |
| | $ | 712 |
| | $ | 539 |
| | $ | 250 |
| | $ | 712 |
|
Accelerated nuclear fuel amortization | | 12 |
| | 60 |
| | 57 |
| | 12 |
| | 60 |
|
Operating and Maintenance | | | | | | | | | | |
One-time charges(d,e) | | 77 |
| | 26 |
| |
One-time charges(e,f) | | | 32 |
| | 77 |
| | 26 |
|
Change in ARO accretion, net of any contractual offset(f)(g) | | — |
| | 2 |
| | — |
| | — |
| | 2 |
|
Contractual offset for ARC depreciation(f)(g) | | — |
| | (86 | ) | | — |
| | — |
| | (86 | ) |
Total | | $ | 339 |
| | $ | 714 |
| | $ | 628 |
| | $ | 339 |
| | $ | 714 |
|
_________
| |
(a) | Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018. |
| |
(b) | Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017. |
| |
(b)(c) | Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates. |
| |
(c)(d) | Reflects incremental accelerated depreciation of plant assets, including any ARC. |
| |
(d)(e) | Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
| |
(e)(f) | In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016. |
| |
(f)(g) | For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission,ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. |
Although
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, is committed to operate through May 2021, the plant faces continued economic challenges andof which Generation owns a 42.59% ownership interest. PSEG asis the operator of Salem and also has the plant, is exploring all options. decision making authority to retire Salem.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 4 - Regulatory Matters for additional information.
The following table provides the balance sheet amounts as of December 31, 20172018 for Generation’s ownership share of the significant assets and liabilities associated with Salem.Salem that would potentially be impacted by a decision to permanently cease generation operations.
|
| | | | |
| | December 31, 2018 |
Asset Balances | | |
Materials and supplies inventory | | $ | 45 |
|
Nuclear fuel inventory, net | | 118 |
|
Completed plant, net | | 538 |
|
Construction work in progress | | 44 |
|
Liability Balances | | |
Asset retirement obligation | | (395 | ) |
| | |
NRC License Renewal Term | | 2036 (unit 1) |
|
| | 2040 (unit 2) |
|
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
Other Generation
On March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currently committed through May 2021.
The ISO-NE announced that it would take a three-step approach to fuel security.
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 capacity commitment periods. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018. |
| | | | |
(in millions) | | 12/31/2017 |
Asset Balances | | |
Materials and supplies inventory | | $ | 44 |
|
Nuclear fuel inventory, net | | 113 |
|
Completed plant, net | | 439 |
|
Construction work in progress | | 33 |
|
Liability Balances | | |
Asset retirement obligation | | (442 | ) |
| | |
NRC License Renewal Term | | 2036 (unit 1) |
|
| | 2040 (unit 2) |
|
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE has indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. Among the costs included in the filing are costs associated with the Everett Marine Terminal. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new methodology. Initial and reply briefs on ROE will be due on April 18, 2019 and July 18, 2019. These will be reflected in a compliance filing due February 2,18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 Exelon announcedorder. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.
The following table provides the balance sheet amounts as of December 31, 2018 for Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that Generation willwould potentially be impacted by a decision to permanently cease generation operations at Oyster Creek atoperations.
|
| | | | |
| | December 31, 2018 |
Asset Balances | | |
Materials and supplies inventory | | $ | 30 |
|
Fuel inventory | | 20 |
|
Completed plant, net | | 901 |
|
Construction work in progress | | 9 |
|
Liability Balances | | |
Asset retirement obligation | | (1 | ) |
To ensure the endcontinued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill recorded. Generation also settled its current operating cycleexisting long-term gas supply agreement, resulting in October 2018. See Note 28 — Subsequent Events for additional information regarding the early retirementa pre-tax gain of Oyster Creek.$75 million, which is included within Purchased power and fuel expense in 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)
9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon's, Generation's, PECO's, BGE's, PHI'sPepco's, DPL's and ACE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 20172018 and 20162017 were as follows:
| | | Nuclear Generation | | Fossil-Fuel Generation | | Transmission | | Other | Nuclear Generation | | Fossil-Fuel Generation | | Transmission | | Other |
| Quad Cities | | Peach Bottom | | Salem(a) | | Nine Mile Point Unit 2 | | Wyman | | PA(b) | | NJ/ DE(c) | | Other(d) | Quad Cities | | Peach Bottom | | Salem(a) | | Nine Mile Point Unit 2 | | Wyman | | PA(b) | | NJ/ DE(c) | | Other(d) |
Operator | Generation | | Generation | | PSEG Nuclear | | Generation | | FP&L | | First Energy | | PSEG/ DPL | | various | Generation | | Generation | | PSEG Nuclear | | Generation | | FP&L | | First Energy | | PSEG/ DPL | | various |
Ownership interest | 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | 5.89 | % | | various |
| | various |
| | various |
| 75.00 | % | | 50.00 | % | | 42.59 | % | | 82.00 | % | | 5.89 | % | | various |
| | various |
| | various |
|
Exelon’s share at December 31, 2018: | | | | | | | | | | | | | | | | |
Plant(e) | | $ | 1,131 |
| | $ | 1,451 |
| | $ | 648 |
| | $ | 910 |
| | $ | 4 |
| | $ | 28 |
| | $ | 103 |
| | $ | 15 |
|
Accumulated depreciation(e) | | 587 |
| | 523 |
| | 227 |
| | 126 |
| | 3 |
| | 16 |
| | 53 |
| | 13 |
|
Construction work in progress | | 13 |
| | 15 |
| | 44 |
| | 56 |
| | — |
| | 1 |
| | — |
| | — |
|
Exelon’s share at December 31, 2017: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Plant(e) | $ | 1,074 |
| | $ | 1,417 |
| | $ | 631 |
| | $ | 839 |
| | $ | 3 |
| | $ | 27 |
| | $ | 102 |
| | $ | 15 |
| $ | 1,074 |
| | $ | 1,417 |
| | $ | 631 |
| | $ | 839 |
| | $ | 3 |
| | $ | 27 |
| | $ | 102 |
| | $ | 15 |
|
Accumulated depreciation(e) | 550 |
| | 461 |
| | 205 |
| | 97 |
| | 3 |
| | 15 |
| | 52 |
| | 13 |
| 550 |
| | 461 |
| | 205 |
| | 97 |
| | 3 |
| | 15 |
| | 52 |
| | 13 |
|
Construction work in progress | 35 |
| | 18 |
| | 33 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
| 35 |
| | 18 |
| | 33 |
| | 55 |
| | — |
| | — |
| | — |
| | — |
|
Exelon’s share at December 31, 2016: | | | | | | | | | | | | | | | | |
Plant(e) | $ | 1,054 |
| | $ | 1,384 |
| | $ | 596 |
| | $ | 830 |
| | $ | 3 |
| | $ | 27 |
| | $ | 97 |
| | $ | 15 |
| |
Accumulated depreciation(e) | 515 |
| | 407 |
| | 186 |
| | 68 |
| | 3 |
| | 15 |
| | 52 |
| | 13 |
| |
Construction work in progress | — |
| | 16 |
| | 41 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 20172018 and 2016.2017. |
| |
(b) | PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above. |
| |
(c) | PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and Delaware Station.of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation. |
| |
(d) | Generation, DPL and ACE own a 44.24%, 4.83%11.91% and 11.91%4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center. |
| |
(e) | Excludes asset retirement costs.costs and general plant. |
Exelon’s, Generation’s, PECO’s, BGE’s,PECO's, BGE's, Pepco's, DPL's and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO’s, BGE’s,PECO's, BGE's, Pepco's, DPL's and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses onin Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses on PECO’s, BGE’s, Pepco,in PECO's, BGE's, Pepco's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
10. Intangible Assets (Exelon, Generation, ComEd, PECO, PHI, Pepco, DPL and ACE)
Goodwill
Exelon’s, Generation's, ComEd’s PHI's and DPL'sPHI's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 20172018 and 20162017 were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at January 1, 2016 | | Goodwill from business combination | | Impairment losses | | Measurement period adjustments (b) | | Balance at December 31, 2016 | | Impairment losses | | Balance at December 31, 2017 |
Exelon | | | | | | | | | | | | | |
Gross amount | $ | 4,655 |
| | $ | 4,016 |
| | $ | — |
| | $ | (11 | ) | | $ | 8,660 |
| | $ | — |
| | $ | 8,660 |
|
Accumulated impairment loss | 1,983 |
| | — |
| | — |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
Carrying amount | 2,672 |
| | 4,016 |
| | — |
| | (11 | ) | | 6,677 |
| | — |
| | 6,677 |
|
Generation | | | | | | | | | | | | |
|
Gross amount | 47 |
| | — |
| | — |
| | — |
| | 47 |
| | — |
| | 47 |
|
Carrying amount | 47 |
| | — |
| | — |
| | — |
| | 47 |
| | — |
| | 47 |
|
ComEd(a) | | | | | | | | | | | | |
|
Gross amount | 4,608 |
| | — |
| | — |
| | — |
| | 4,608 |
| | — |
| | 4,608 |
|
Accumulated impairment loss | 1,983 |
| | — |
| | — |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
Carrying amount | 2,625 |
| | — |
| | — |
| | — |
| | 2,625 |
| | — |
| | 2,625 |
|
DPL | | | | | | | | | | | | |
|
Gross amount | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | 8 |
|
Carrying amount | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | 8 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | For the Year Ended December 31, 2017 | Beginning Balance | | Goodwill from business combination | | Impairment losses | | Measurement period adjustments (b) | | Ending Balance | |
PHI - Successor | | | | | | | | | | |
Gross amount | $ | 4,005 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 4,005 |
| |
Accumulated impairment loss | — |
| | — |
| | — |
| | — |
| | — |
| |
Carrying Amount | 4,005 |
| | — |
| | — |
| | — |
| | 4,005 |
| |
| | | | | | | | | | Balance at January 1, 2017 | | Impairment losses | | Balance at December 31, 2017 | | Impairment losses | | Balance at December 31, 2018 |
March 24, 2016 to December 31, 2016
| | | | | | | | | | |
PHI - Successor | | | | | | | | | | |
Exelon | | | | | | | | | | |
Gross amount | — |
| | 4,016 |
| | — |
| | (11 | ) | | 4,005 |
| $ | 8,660 |
| | $ | — |
| | $ | 8,660 |
| | $ | — |
| | $ | 8,660 |
|
Accumulated impairment loss | — |
| | — |
| | — |
| | — |
| | — |
| 1,983 |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
Carrying amount | — |
| | 4,016 |
| | — |
| | (11 | ) | | 4,005 |
| 6,677 |
| | — |
| | 6,677 |
| | — |
| | 6,677 |
|
| | | | | | | | | | |
January 1, 2016 to March 23, 2016 | | | | | | | | | | |
PHI - Predecessor | | | | | | | | | | |
ComEd(a) | | | | | | | | | |
|
Gross amount | 1,418 |
| | — |
| | — |
| | — |
| | 1,418 |
| 4,608 |
| | — |
| | 4,608 |
| | — |
| | 4,608 |
|
Accumulated impairment loss | 12 |
| | — |
| | — |
| | — |
| | 12 |
| 1,983 |
| | — |
| | 1,983 |
| | — |
| | 1,983 |
|
Carrying amount | 1,406 |
| | — |
| | — |
| | — |
| | 1,406 |
| 2,625 |
| | — |
| | 2,625 |
| | — |
| | 2,625 |
|
PHI(b) | | | | | | | | | | |
Gross amount | | 4,005 |
| | — |
| | 4,005 |
| | — |
| | 4,005 |
|
Carrying amount | | 4,005 |
| | — |
| | 4,005 |
| | — |
| | 4,005 |
|
__________
| |
(a) | Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.. |
| |
(b) | Represents various measurement period adjustments toReflects goodwill recorded in 2016 from the valuation of the fair value of the PHI assets acquired and liabilities assumed as a result of the merger. |
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the Exelon, Generation, ComEd, PHIComEd's and DPLPHI's reporting unitunits below itstheir carrying amount. Under the authoritative guidance for goodwill, aamounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. Generation'sComEd has a single operating segments are Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”,segment. PHI's operating segments are Pepco, DPL and ACE, and ComEd and DPL have a single operating segment.ACE. See Note 2524 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit,unit. PHI identified an error related to the allocation of goodwill to its reporting units in 2016 while performing the 2018 annual impairment assessment. As revised in 2018, Exelon's and PHI's $4 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $1.7$2.1 billion, $1.1$1.4 billion and $1.2$0.5 billion, respectively. DPL's $8 millionrespectively, an increase (decrease) of $0.4 billion, $0.3 billion, and $(0.7) billion for Pepco, DPL and ACE, respectively, from the originally reported amounts. This error did not result in a change to the total amount of goodwill recorded at PHI nor would it have resulted in an impairment of PHI's goodwill in 2016 or 2017. Therefore, management has concluded that the error is assigned entirelynot material to the DPL reporting unit.previously issued financial statements.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment, entities should assess, among other things, macroeconomic conditions, industry and market considerations, overall financial performance, cost factors and entity-specific events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
If an entity bypasses the qualitative assessment or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative two-step, fair value-based test is performed. Exelon's, Generation's, ComEd's PHI's and DPL'sPHI's accounting policy is to perform a quantitative test of goodwill at least once every three years. The first step in the quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation accountingauthoritative guidance in order to determine the implied fair value of goodwill. If the implied
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.
Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for Generation's, ComEd's, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.
20172018 and 20162017 Goodwill Impairment Assessment. Generation performed a quantitative test as of November 1, 2017, for its 2017 annual goodwill impairment assessment. The first step of the test comparing the estimated fair value of Generation's reporting unit with goodwill to its carrying value, including goodwill, indicated no impairments of goodwill; therefore, the second step was not required. Generation performed a qualitative test as of November 1, 2016, for its 2016 annual goodwill impairment assessment. Based on the qualitative factors assessed, Generation concluded that the fair value of its reporting units is more likely than not greater than the carrying amount,ComEd and no further testing was required.
As of November 1, 2017, ComEd, PHI and DPL each qualitatively determined that it was more likely than not that the fair valuevalues of itstheir reporting units exceeded their carrying values and, therefore, did not perform a quantitative assessment.assessments as of November 1, 2018 and 2017 for ComEd and as of November 1, 2017 for PHI. As part of their qualitative assessments, ComEd PHI and DPLPHI evaluated, among other things, management’s best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer company EBITDA multiples, while also considering, the passing margin from their last quantitative assessments.
ComEd, PHI and DPL performed quantitative testsassessments as of November 1, 2016,2016.
As a result of the reallocation of goodwill to PHI’s reporting units as discussed above, as of November 1, 2018, PHI performed a quantitative test for their 2016its 2018 annual goodwill impairment assessments.assessment. The first step of the teststest comparing the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second steps werestep was required.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's and PHI’s or DPL’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%30%, 10%20% and 10%30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests. The $8 million of goodwill recorded at DPL is related to DPL’s 1995 acquisition of the Conowingo Power Company and the fair value of the DPL reporting unit would have needed to decrease by more than 50% for DPL to fail the first step of the impairment test.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other Intangible Assets and Liabilities
Exelon’s, Generation’s, ComEd’s and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 20172018 and 2016:2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2017 | | December 31, 2016 |
| | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
Exelon | | | | | | | | | | | | |
Software License(a) | | $ | 95 |
| | $ | (25 | ) | | $ | 70 |
| | $ | 95 |
| | $ | (15 | ) | | $ | 80 |
|
Generation | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | 1,938 |
| | (1,574 | ) | | 364 |
| | 1,926 |
| | (1,543 | ) | | 383 |
|
Customer Relationships | | 305 |
| | (133 | ) | | 172 |
| | 299 |
| | (109 | ) | | 190 |
|
Trade Name | | 243 |
| | (148 | ) | | 95 |
| | 243 |
| | (125 | ) | | 118 |
|
Service Contract Backlog | | — |
| | — |
| | — |
| | 9 |
| | (7 | ) | | 2 |
|
ComEd | | | | | |
| | | | | |
|
Chicago Settlement Agreements(c) | | 162 |
| | (141 | ) | | 21 |
| | 162 |
| | (133 | ) | | 29 |
|
PHI | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | (1,515 | ) | | 766 |
| | (749 | ) | | (1,515 | ) | | 430 |
| | (1,085 | ) |
Pepco | | | | | |
| | | | | |
|
DC Sponsorship Agreement(d) | | — |
| | — |
| | — |
| | 25 |
| | — |
| | 25 |
|
Total | | $ | 1,228 |
| | $ | (1,255 | ) | | $ | (27 | ) | | $ | 1,244 |
| | $ | (1,502 | ) | | $ | (258 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | December 31, 2018 | | December 31, 2017 |
| | Gross | | Accumulated Amortization | | Net | | Gross | | Accumulated Amortization | | Net |
Generation | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | 1,957 |
| | (1,588 | ) | | 369 |
| | 1,938 |
| | (1,574 | ) | | 364 |
|
Customer Relationships | | 325 |
| | (162 | ) | | 163 |
| | 305 |
| | (133 | ) | | 172 |
|
Trade Name | | 243 |
| | (171 | ) | | 72 |
| | 243 |
| | (148 | ) | | 95 |
|
ComEd | | | | | |
| | | | | |
|
Chicago Settlement Agreements(c) | | 162 |
| | (148 | ) | | 14 |
| | 162 |
| | (141 | ) | | 21 |
|
PHI | | | | | |
| | | | | |
|
Unamortized Energy Contracts(b) | | (1,515 | ) | | 954 |
| | (561 | ) | | (1,515 | ) | | 766 |
| | (749 | ) |
Exelon Corporate | | | | | | | | | | | | |
Software License(a) | | 95 |
| | (34 | ) | | 61 |
| | 95 |
| | (25 | ) | | 70 |
|
Exelon | | $ | 1,267 |
| | $ | (1,149 | ) | | $ | 118 |
| | $ | 1,228 |
| | $ | (1,255 | ) | | $ | (27 | ) |
__________
| |
(a) | On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term. |
| |
(b) | Includes unamortized energy contract assets and liabilities onin Exelon's, Generations and PHI's Consolidated Balance Sheets. |
| |
(c) | In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement. |
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2018:
|
| | | | | | | | | | | | | | | | |
For the Years Ending December 31, | | Exelon | | Generation | | ComEd | | PHI |
2019 | | $ | (32 | ) | | $ | 70 |
| | $ | 7 |
| | $ | (119 | ) |
2020 | | (20 | ) | | 78 |
| | 7 |
| | (115 | ) |
2021 | | (4 | ) | | 78 |
| | — |
| | (92 | ) |
2022 | | (23 | ) | | 56 |
| | — |
| | (89 | ) |
2023 | | (21 | ) | | 50 |
| | — |
| | (81 | ) |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2018, 2017 and 2016:
|
| | | | | | | | | | | | | | | | |
For the Years Ended December 31, | | Exelon (a)(b) | | Generation (a) | | ComEd | | PHI(b) |
2018 | | $ | (109 | ) | | $ | 63 |
| | $ | 7 |
| | $ | (188 | ) |
2017 | | (237 | ) | | 83 |
| | 7 |
| | (336 | ) |
2016 | | (336 | ) | | 79 |
| | 7 |
| | (430 | ) |
__________
| |
(d)(a) | PHI entered into a sponsorship agreement withAt Exelon and Generation, amortization of unamortized energy contracts totaling $14 million, $35 million and $35 million for the Districtyears ended December 31, 2018, 2017 and 2016, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Columbia for future sponsorship rights associated with public property within the District of Columbia. In December 2017, the asset was written off. See Note 7 - Impairment of Long-Lived AssetsOperations and Intangibles for additional information.Comprehensive Income. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2017:
|
| | | | | | | | | | | | | | | | |
For the Years Ending December 31, | | Exelon | | Generation | | ComEd | | PHI |
2018 | | $ | 10 |
| | $ | 62 |
| | $ | 7 |
| | $ | (189 | ) |
2019 | | 10 |
| | 57 |
| | 7 |
| | (119 | ) |
2020 | | 10 |
| | 68 |
| | 7 |
| | (115 | ) |
2021 | | 10 |
| | 77 |
| | — |
| | (92 | ) |
2022 | | 10 |
| | 54 |
| | — |
| | (89 | ) |
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2017, 2016 and 2015:
|
| | | | | | | | | | | |
For the Years Ended December 31, | Exelon (a) | | Generation (a) | | ComEd |
2017 | $ | 92 |
| | $ | 83 |
| | $ | 7 |
|
2016 | 87 |
| | 79 |
| | 7 |
|
2015 | 76 |
| | 69 |
| | 7 |
|
__________
(a) At Exelon, amortization of unamortized energy contracts totaling $35 million, $35 million and $22 million for the years ended December 31, 2017, 2016 and 2015, respectively, was recorded in Operating revenues or Purchased power and fuel expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $35 million, $35 million and $22 million for the years ended December 31, 2017, 2016 and 2015, respectively, was recorded in Operating revenues or Purchased power and fuel expense within Generation’s Consolidated Statements of Operations and Comprehensive Income
| |
(b) | At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income. |
Acquired Intangible Assets and Liabilities
Accounting guidance for businessBusiness combinations requiresrequire the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.
Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Exelon and Generation have acquired.The valuation of unamortized energy contracts was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise, the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accountingauthoritative guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The Exelon Wind unamortized energy contracts are amortized on a straight-line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenues within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG, Integrys and ConEdison, the fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition dates through either Operating revenues or Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. At PHI, offsetting regulatory assets or liabilities were also recorded. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Customer Relationships. The customer relationship intangibles were determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accountingauthoritative guidance. Key assumptions include the customer attrition rate and the discount rate. The accountingauthoritative guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Service Contract Backlog. The service contract backlog intangibles were determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the contracts. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include estimated revenues and expenses to complete the contracts as well as the discount rate. The accounting guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the service contract backlog is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accountingauthoritative guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, PECO, PHI, DPL and ACE)
Exelon’s, Generation’s, ComEd’s, PECO's, PHI's, DPL's and ACE's other intangible assets, included in Other current assets and Other deferred debits and other assets onin the Consolidated Balance Sheets, include RECs (Exelon, Generation, ComEd, PHI, DPL and ACE) and AECs (Exelon and PECO). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are part ofsold to a bundledcounterparty under a contract that specifically identifies a power saleplant is recognized at a point in time when the power is producedproduced. This includes both bundled and delivered to the customer, otherwise,unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC.REC to the customer.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the current and noncurrent Renewable and Alternative Energy Credits for the years endedas of December 31, 20172018 and 2016:2017:
| | | As of December 31, 2017 | | | | | | | | | | | | | |
| | | | | | | Successor | | | | | As of December 31, 2018 |
| Exelon | | Generation | | PECO | | PHI | | DPL | | ACE | Exelon | | Generation | | PECO | | PHI | | DPL | | ACE |
Current AEC's | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Noncurrent AEC's | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Current REC's | 321 |
| | 312 |
| | — |
| | 9 |
| | 8 |
| | 1 |
| 279 |
| | 270 |
| | — |
| | 9 |
| | 8 |
| | 1 |
|
Noncurrent REC's | 27 |
| | 27 |
| | — |
| | — |
| | — |
| | — |
| 52 |
| | 52 |
| | — |
| | — |
| | — |
| | — |
|
| As of December 31, 2016 | As of December 31, 2017 |
| | | | | | | Successor | | | | | Exelon | | Generation | | PECO | | PHI | | DPL | | ACE |
| Exelon | | Generation | | PECO | | PHI | | DPL | | ACE | |
Current AEC's | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Noncurrent AEC's | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Current REC's | 330 |
| | 318 |
| | — |
| | 12 |
| | 11 |
| | 1 |
| 321 |
| | 312 |
| | — |
| | 9 |
| | 8 |
| | 1 |
|
Noncurrent REC's | 29 |
| | 29 |
| | — |
| | — |
| | — |
| | — |
| 27 |
| | 27 |
| | — |
| | — |
| | — |
| | — |
|
11. Fair Value of Financial Assets and Liabilities (All Registrants)
Fair Value of Financial Liabilities Recorded at the Carrying Amount
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 20172018 and 2016:2017:
Exelon
| | | December 31, 2017 | December 31, 2018 |
| 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 | $ | 929 |
| | $ | — |
|
| $ | 929 |
|
| $ | — |
| | $ | 929 |
| $ | 714 |
| | $ | — |
|
| $ | 714 |
|
| $ | — |
| | $ | 714 |
|
Long-term debt (including amounts due within one year)(a) | 34,264 |
| | — |
|
| 34,735 |
|
| 1,970 |
| | 36,705 |
| 35,424 |
| | — |
|
| 33,711 |
|
| 2,158 |
| | 35,869 |
|
Long-term debt to financing trusts(b) | 389 |
| | — |
|
| — |
|
| 431 |
| | 431 |
| 390 |
| | — |
|
| — |
|
| 400 |
| | 400 |
|
SNF obligation | 1,147 |
| | — |
|
| 936 |
|
| — |
| | 936 |
| 1,171 |
| | — |
|
| 949 |
|
| — |
| | 949 |
|
| | | December 31, 2016 | December 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 | $ | 1,267 |
| | $ | — |
| | $ | 1,267 |
| | $ | — |
| | $ | 1,267 |
| $ | 929 |
| | $ | — |
| | $ | 929 |
| | $ | — |
| | $ | 929 |
|
Long-term debt (including amounts due within one year)(a) | 34,005 |
| | 1,113 |
| | 31,741 |
| | 1,959 |
| | 34,813 |
| 34,264 |
| | — |
| | 34,735 |
| | 1,970 |
| | 36,705 |
|
Long-term debt to financing trusts(b) | 641 |
| | — |
| | — |
| | 667 |
| | 667 |
| 389 |
| | — |
| | — |
| | 431 |
| | 431 |
|
SNF obligation | 1,024 |
| | — |
| | 732 |
| | — |
| | 732 |
| 1,147 |
| | — |
| | 936 |
| | — |
| | 936 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
| | | December 31, 2017 | December 31, 2018 |
| 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 | $ | 2 |
| | $ | — |
|
| $ | 2 |
|
| $ | — |
| | $ | 2 |
| |
Long-term debt (including amounts due within one year)(a) | 8,990 |
| | — |
|
| 7,839 |
|
| 1,673 |
| | 9,512 |
| $ | 8,793 |
| | $ | — |
|
| $ | 7,467 |
|
| $ | 1,443 |
| | $ | 8,910 |
|
SNF obligation | 1,147 |
| | — |
|
| 936 |
|
| — |
| | 936 |
| 1,171 |
| | — |
|
| 949 |
|
| — |
| | 949 |
|
| | | December 31, 2016 | December 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 | $ | 699 |
| | $ | — |
| | $ | 699 |
| | $ | — |
| | $ | 699 |
| $ | 2 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 2 |
|
Long-term debt (including amounts due within one year)(a) | 9,241 |
| | — |
| | 7,482 |
| | 1,670 |
| | 9,152 |
| 8,990 |
| | — |
| | 7,839 |
| | 1,673 |
| | 9,512 |
|
SNF obligation | 1,024 |
| | — |
| | 732 |
| | — |
| | 732 |
| 1,147 |
| | — |
| | 936 |
| | — |
| | 936 |
|
ComEd
| | | December 31, 2017 | December 31, 2018 |
| Carrying Amount | | Fair Value | Carrying Amount | | Fair Value |
| Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 7,601 |
| | $ | — |
|
| $ | 8,418 |
|
| $ | — |
| | $ | 8,418 |
| $ | 8,101 |
| | $ | — |
|
| $ | 8,390 |
|
| $ | — |
| | $ | 8,390 |
|
Long-term debt to financing trusts(b) | 205 |
| | — |
|
| — |
|
| 227 |
| | 227 |
| 205 |
| | — |
|
| — |
|
| 209 |
| | 209 |
|
| | | December 31, 2016 | December 31, 2017 |
| Carrying Amount | | Fair Value | Carrying Amount | | Fair Value |
| Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 7,033 |
| | $ | — |
| | $ | 7,585 |
| | $ | — |
| | $ | 7,585 |
| $ | 7,601 |
| | $ | — |
| | $ | 8,418 |
| | $ | — |
| | $ | 8,418 |
|
Long-term debt to financing trusts(b) | 205 |
| | — |
| | — |
| | 215 |
| | 215 |
| 205 |
| | — |
| | — |
| | 227 |
| | 227 |
|
PECO
| | | December 31, 2017 | December 31, 2018 |
| Carrying Amount | | Fair Value | Carrying Amount | | Fair Value |
| Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 2,903 |
| | $ | — |
|
| $ | 3,194 |
|
| $ | — |
| | $ | 3,194 |
| $ | 3,084 |
| | $ | — |
|
| $ | 3,157 |
|
| $ | 50 |
| | $ | 3,207 |
|
Long-term debt to financing trusts | 184 |
| | — |
|
| — |
|
| 204 |
| | 204 |
| 184 |
| | — |
|
| — |
|
| 191 |
| | 191 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 2,903 |
| | $ | — |
| | $ | 3,194 |
| | $ | — |
| | $ | 3,194 |
|
Long-term debt to financing trusts | 184 |
| | — |
| | — |
| | 204 |
| | 204 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
| 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
| | | December 31, 2017 | December 31, 2018 |
| 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 | $ | 77 |
| | $ | — |
|
| $ | 77 |
|
| $ | — |
| | $ | 77 |
| $ | 35 |
| | $ | — |
|
| $ | 35 |
|
| $ | — |
| | $ | 35 |
|
Long-term debt (including amounts due within one year)(a) | 2,577 |
| | — |
|
| 2,825 |
|
| — |
| | 2,825 |
| 2,876 |
| | — |
|
| 2,950 |
|
| — |
| | 2,950 |
|
| | | December 31, 2016 | December 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 | $ | 45 |
| | $ | — |
| | $ | 45 |
| | $ | — |
| | $ | 45 |
| $ | 77 |
| | $ | — |
| | $ | 77 |
| | $ | — |
| | $ | 77 |
|
Long-term debt (including amounts due within one year)(a) | 2,322 |
| | — |
| | 2,467 |
| | — |
| | 2,467 |
| 2,577 |
| | — |
| | 2,825 |
| | — |
| | 2,825 |
|
Long-term debt to financing trusts(b) | 252 |
| | — |
| | — |
| | 260 |
| | 260 |
| |
PHI (Successor)
| | | December 31, 2017 | December 31, 2018 |
| 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 | $ | 350 |
| | $ | — |
| | $ | 350 |
| | $ | — |
| | $ | 350 |
| $ | 179 |
| | $ | — |
| | $ | 179 |
| | $ | — |
| | $ | 179 |
|
Long-term debt (including amounts due within one year)(a) | 5,874 |
| | — |
| | 5,722 |
| | 297 |
| | 6,019 |
| 6,259 |
| | — |
| | 5,436 |
| | 665 |
| | 6,101 |
|
| | | December 31, 2016 | December 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 | $ | 522 |
| | $ | — |
| | $ | 522 |
| | $ | — |
| | $ | 522 |
| $ | 350 |
| | $ | — |
| | $ | 350 |
| | $ | — |
| | $ | 350 |
|
Long-term debt (including amounts due within one year)(a) | 5,898 |
| | — |
| | 5,520 |
| | 289 |
| | 5,809 |
| 5,874 |
| | — |
| | 5,722 |
| | 297 |
| | 6,019 |
|
Pepco
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2018 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 40 |
| | $ | — |
| | $ | 40 |
| | $ | — |
| | $ | 40 |
|
Long-term debt (including amounts due within one year)(a) | 2,719 |
| | — |
| | 2,901 |
| | 196 |
| | 3,097 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 26 |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
|
Long-term debt (including amounts due within one year)(a) | 2,540 |
| | — |
| | 3,114 |
| | 9 |
| | 3,123 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 26 |
| | $ | — |
| | $ | 26 |
| | $ | — |
| | $ | 26 |
|
Long-term debt (including amounts due within one year)(a) | 2,540 |
| | — |
| | 3,114 |
| | 9 |
| | 3,123 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 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
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 216 |
| | $ | — |
| | $ | 216 |
| | $ | — |
| | $ | 216 |
|
Long-term debt (including amounts due within one year)(a) | 1,300 |
| | — |
| | 1,393 |
| | — |
| | 1,393 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2018 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Long-term debt (including amounts due within one year)(a) | $ | 1,494 |
| | $ | — |
| | $ | 1,303 |
| | $ | 193 |
| | $ | 1,496 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 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 |
|
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 216 |
| | $ | — |
| | $ | 216 |
| | $ | — |
| | $ | 216 |
|
Long-term debt (including amounts due within one year)(a) | 1,300 |
| | — |
| | 1,393 |
| | — |
| | 1,393 |
|
ACE
| | | December 31, 2017 | December 31, 2018 |
| 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 | $ | 108 |
| | $ | — |
| | $ | 108 |
| | $ | — |
| | $ | 108 |
| $ | 139 |
| | $ | — |
| | $ | 139 |
| | $ | — |
| | $ | 139 |
|
Long-term debt (including amounts due within one year)(a) | 1,121 |
| | — |
| | 949 |
| | 288 |
| | 1,237 |
| 1,188 |
| | — |
| | 987 |
| | 275 |
| | 1,262 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 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 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
| December 31, 2017 |
| Carrying Amount | | Fair Value |
| | Level 1 | | Level 2 | | Level 3 | | Total |
Short-term liabilities | $ | 108 |
| | $ | — |
| | $ | 108 |
| | $ | — |
| | $ | 108 |
|
Long-term debt (including amounts due within one year)(a) | 1,121 |
| | — |
| | 949 |
| | 288 |
| | 1,237 |
|
__________
| |
(a) | Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32(a) Includes unamortized debt issuance costs which are not fair valued of $216 million, $51 million, $63 million, $23 million, $18 million, $14 million, $34 million, $12 million and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $201 million, $60 million, $52 million, $17 million, $17 million, $6 million, $32 million, $11 million and $5 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2017. (b) Includes unamortized debt issuance costs which are not fair valued of $0 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017. Includes unamortized debt issuance costs which are not fair valued of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2016. |
| |
(b) | Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017. 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 December 31, 2016. |
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in Other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.
Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 Pepco's non-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 or off-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 financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.
SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030. The carrying amount also includes $119 million and $114 million as of December 31, 2018 and 2017for the one-time fee obligation associated with closing of the FitzPatrick acquisition on 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 45 - 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.
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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars 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 material transfers between Level 1 and Level 2 during the years ended December 31, 2017 and 2016 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.millions, except per share data unless otherwise noted)
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.
The following tables present assets and liabilities measured and recorded at fair value onin Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 20172018 and 2016:2017:
| | | Generation | | Exelon | Generation | | Exelon |
As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | |
As of December 31, 2018 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 168 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 168 |
| | $ | 656 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 656 |
| $ | 581 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 581 |
| | $ | 1,243 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1,243 |
|
NDT fund investments | | | | | | | | | |
|
| | | | | | | | | |
|
|
Cash equivalents(b) | | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
| | 252 |
| | 86 |
| | — |
| | — |
| | 338 |
|
Equities | | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
| | 2,918 |
| | 1,591 |
| | — |
| | 1,381 |
| | 5,890 |
|
Fixed income | |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
|
Corporate debt | | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
| | — |
| | 1,593 |
| | 230 |
| | — |
| | 1,823 |
|
U.S. Treasury and agencies | | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
| | 2,081 |
| | 99 |
| | — |
| | — |
| | 2,180 |
|
Foreign governments | | — |
| | 50 |
| | — |
| | — |
| | 50 |
| | — |
| | 50 |
| | — |
| | — |
| | 50 |
|
State and municipal debt | | — |
| | 149 |
| | — |
| | — |
| | 149 |
| | — |
| | 149 |
| | — |
| | — |
| | 149 |
|
Other(c) | | — |
| | 30 |
| | — |
| | 846 |
| | 876 |
| | — |
| | 30 |
| | — |
| | 846 |
|
| 876 |
|
Fixed income subtotal | | 2,081 |
| | 1,921 |
| | 230 |
|
| 846 |
| | 5,078 |
| | 2,081 |
| | 1,921 |
| | 230 |
| | 846 |
| | 5,078 |
|
Middle market lending | | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
| | — |
| | — |
| | 313 |
| | 367 |
| | 680 |
|
Private equity | | — |
| | — |
| | — |
| | 329 |
| | 329 |
| | — |
| | — |
| | — |
| | 329 |
| | 329 |
|
Real estate | | — |
| | — |
| | — |
| | 510 |
| | 510 |
| | — |
| | — |
| | — |
| | 510 |
| | 510 |
|
NDT fund investments subtotal(d) | | 5,251 |
| | 3,598 |
| | 543 |
| | 3,433 |
|
| 12,825 |
|
| 5,251 |
| | 3,598 |
| | 543 |
|
| 3,433 |
|
| 12,825 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Generation | | Exelon | Generation | | Exelon |
As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | |
NDT fund investments | | | | | | | | |
|
| | | | | | | | | |
|
| |
As of December 31, 2018 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pledged assets for Zion Station decommissioning | |
| |
| |
| | | |
| |
| |
| |
| | | |
|
Cash equivalents(b) | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
| | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
| 9 |
| | — |
| | — |
| | — |
| | 9 |
| | 9 |
| | — |
| | — |
| | — |
| | 9 |
|
Equities | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
| | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
| |
Fixed income |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
| |
Corporate debt | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
| | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
| |
U.S. Treasury and agencies | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
| | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
| |
Foreign governments | — |
| | 82 |
| | — |
| | — |
| | 82 |
| | — |
| | 82 |
| | — |
| | — |
| | 82 |
| |
State and municipal debt | — |
| | 263 |
| | — |
| | — |
| | 263 |
| | — |
| | 263 |
| | — |
| | — |
| | 263 |
| |
Other(c) | — |
| | 47 |
| | — |
| | 510 |
| | 557 |
| | — |
| | 47 |
| | — |
| | 510 |
|
| 557 |
| |
Fixed income subtotal | 1,917 |
| | 2,058 |
| | 251 |
|
| 510 |
| | 4,736 |
| | 1,917 |
| | 2,058 |
| | 251 |
| | 510 |
| | 4,736 |
| |
Middle market lending | — |
| | — |
| | 397 |
| | 131 |
| | 528 |
| | — |
| | — |
| | 397 |
| | 131 |
| | 528 |
| |
Private equity | — |
| | — |
| | — |
| | 222 |
| | 222 |
| | — |
| | — |
| | — |
| | 222 |
| | 222 |
| |
Real estate | — |
| | — |
| | — |
| | 471 |
| | 471 |
| | — |
| | — |
| | — |
| | 471 |
| | 471 |
| |
NDT fund investments subtotal(d) | 6,215 |
| | 3,058 |
| | 648 |
| | 3,510 |
|
| 13,431 |
|
| 6,215 |
| | 3,058 |
| | 648 |
|
| 3,510 |
|
| 13,431 |
| |
Pledged assets for Zion Station decommissioning |
| |
| |
| | | |
| |
| |
| |
| | | |
| |
Cash equivalents | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| |
Equities | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Middle market lending | — |
| | — |
| | 12 |
| | 24 |
| | 36 |
| | — |
| | — |
| | 12 |
| | 24 |
| | 36 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Pledged assets for Zion Station decommissioning subtotal | 2 |
| | 1 |
| | 12 |
|
| 24 |
|
| 39 |
|
| 2 |
| | 1 |
| | 12 |
|
| 24 |
|
| 39 |
| 9 |
| | — |
| | — |
|
| — |
|
| 9 |
|
| 9 |
| | — |
| | — |
|
| — |
|
| 9 |
|
Rabbi trust investments |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| |
| |
| | | |
| |
| |
| |
| | | |
|
Cash equivalents | 5 |
| | — |
| | — |
| | — |
| | 5 |
| | 77 |
| | — |
| | — |
| | — |
| | 77 |
| 5 |
| | — |
| | — |
| | — |
| | 5 |
| | 48 |
| | — |
| | — |
| | — |
| | 48 |
|
Mutual funds | 23 |
| | — |
| | — |
| | — |
| | 23 |
| | 58 |
| | — |
| | — |
| | — |
| | 58 |
| 24 |
| | — |
| | — |
| | — |
| | 24 |
| | 72 |
| | — |
| | — |
| | — |
| | 72 |
|
Fixed income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 15 |
| | — |
| | — |
| | 15 |
|
Life insurance contracts | — |
| | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | 71 |
| | 22 |
| | — |
| | 93 |
| — |
| | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | 70 |
| | 38 |
| | — |
| | 108 |
|
Rabbi trust investments subtotal | 28 |
| | 22 |
| | — |
| | — |
|
| 50 |
|
| 135 |
| | 83 |
| | 22 |
| | — |
|
| 240 |
| |
Rabbi trust investments subtotal(f) | | 29 |
| | 22 |
| | — |
| | — |
|
| 51 |
|
| 120 |
| | 85 |
| | 38 |
| | — |
|
| 243 |
|
Commodity derivative assets |
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
|
| |
| |
| | | |
|
| |
| |
| |
| | | |
|
|
Economic hedges | 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
| | 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
| 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
| | 541 |
| | 2,760 |
| | 1,470 |
| | — |
| | 4,771 |
|
Proprietary trading | 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
| | 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
| — |
| | 69 |
| | 77 |
| | — |
| | 146 |
| | — |
| | 69 |
| | 77 |
| | — |
| | 146 |
|
Effect of netting and allocation of collateral(e)(f) | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) | | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) | |
Effect of netting and allocation of collateral(e) | | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) | | (582 | ) | | (2,357 | ) | | (732 | ) | | — |
| | (3,671 | ) |
Commodity derivative assets subtotal | (26 | ) | | 640 |
| | 690 |
|
| — |
|
| 1,304 |
|
| (26 | ) | | 640 |
| | 690 |
|
| — |
|
| 1,304 |
| (41 | ) | | 472 |
| | 815 |
|
| — |
|
| 1,246 |
|
| (41 | ) | | 472 |
| | 815 |
|
| — |
|
| 1,246 |
|
Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Economic hedges | | — |
| | 13 |
| | — |
| | — |
| | 13 |
| | — |
| | 13 |
| | — |
| | — |
| | 13 |
|
Effect of netting and allocation of collateral | | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
Interest rate and foreign currency derivative assets subtotal | | — |
| | 10 |
| | — |
|
| — |
|
| 10 |
|
| — |
| | 10 |
| | — |
|
| — |
|
| 10 |
|
Other investments | | — |
| | — |
| | 42 |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
| | — |
| | 42 |
|
Total assets | | 5,829 |
| | 4,102 |
| | 1,400 |
|
| 3,433 |
|
| 14,764 |
|
| 6,582 |
| | 4,165 |
| | 1,438 |
|
| 3,433 |
|
| 15,618 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Generation | | Exelon | Generation | | Exelon |
As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | |
Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 6 |
| | — |
| | — |
| | 6 |
| |
Economic hedges | — |
| | 10 |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
| |
Effect of netting and allocation of collateral | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) | | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) | |
Interest rate and foreign currency derivative assets subtotal | (2 | ) | | 8 |
| | — |
|
| — |
|
| 6 |
|
| (2 | ) | | 11 |
| | — |
|
| — |
|
| 9 |
| |
Other investments | — |
| | — |
| | 37 |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
| |
Total assets | 6,385 |
| | 3,729 |
| | 1,387 |
|
| 3,534 |
|
| 15,035 |
|
| 6,980 |
| | 3,793 |
| | 1,409 |
|
| 3,534 |
|
| 15,716 |
| |
As of December 31, 2018 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
|
|
| |
| |
| | | |
| |
| |
| |
| | | |
|
|
Commodity derivative liabilities |
| |
| |
| | | |
| |
| |
| |
| | | |
|
| |
| |
| | | |
| |
| |
| |
| | | |
|
Economic hedges | (712 | ) | | (2,226 | ) | | (845 | ) | | — |
| | (3,783 | ) | | (713 | ) | | (2,226 | ) | | (1,101 | ) | | — |
| | (4,040 | ) | (642 | ) | | (2,963 | ) | | (1,027 | ) | | — |
| | (4,632 | ) | | (642 | ) | | (2,963 | ) | | (1,276 | ) | | — |
| | (4,881 | ) |
Proprietary trading | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) | | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) | | — |
| | (73 | ) | | (21 | ) | | — |
| | (94 | ) |
Effect of netting and allocation of collateral(e)(f) | 650 |
| | 2,089 |
| | 716 |
| | — |
| | 3,455 |
| | 651 |
| | 2,089 |
| | 716 |
| | — |
| | 3,456 |
| |
Effect of netting and allocation of collateral(e) | | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
| | 639 |
| | 2,581 |
| | 808 |
| | — |
| | 4,028 |
|
Commodity derivative liabilities subtotal | (64 | ) | | (179 | ) | | (138 | ) |
| — |
|
| (381 | ) |
| (64 | ) | | (179 | ) | | (394 | ) |
| — |
|
| (637 | ) | (3 | ) | | (455 | ) | | (240 | ) |
| — |
|
| (698 | ) |
| (3 | ) | | (455 | ) | | (489 | ) |
| — |
|
| (947 | ) |
Interest rate and foreign currency derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| | (4 | ) |
Economic hedges | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) | | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) | | — |
| | (6 | ) | | — |
| | — |
| | (6 | ) |
Effect of netting and allocation of collateral | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
| | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
| — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
Interest rate and foreign currency derivative liabilities subtotal | 1 |
| | (5 | ) | | — |
|
| — |
|
| (4 | ) |
| 1 |
| | (5 | ) | | — |
|
| — |
|
| (4 | ) | — |
| | (3 | ) | | — |
|
| — |
|
| (3 | ) |
| — |
| | (7 | ) | | — |
|
| — |
|
| (7 | ) |
Deferred compensation obligation | — |
| | (38 | ) | | — |
| | — |
| | (38 | ) | | — |
| | (145 | ) | | — |
| | — |
| | (145 | ) | — |
| | (35 | ) | | — |
| | — |
| | (35 | ) | | — |
| | (137 | ) | | — |
| | — |
| | (137 | ) |
Total liabilities | (63 | ) | | (222 | ) | | (138 | ) |
| — |
|
| (423 | ) |
| (63 | ) | | (329 | ) | | (394 | ) |
| — |
|
| (786 | ) | (3 | ) | | (493 | ) | | (240 | ) |
| — |
|
| (736 | ) |
| (3 | ) | | (599 | ) | | (489 | ) |
| — |
|
| (1,091 | ) |
Total net assets | $ | 6,322 |
| | $ | 3,507 |
| | $ | 1,249 |
|
| $ | 3,534 |
|
| $ | 14,612 |
|
| $ | 6,917 |
| | $ | 3,464 |
| | $ | 1,015 |
|
| $ | 3,534 |
|
| $ | 14,930 |
| $ | 5,826 |
| | $ | 3,609 |
| | $ | 1,160 |
|
| $ | 3,433 |
|
| $ | 14,028 |
|
| $ | 6,579 |
| | $ | 3,566 |
| | $ | 949 |
|
| $ | 3,433 |
|
| $ | 14,527 |
|
| | | Generation | | Exelon | Generation | | Exelon |
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 | |
As of December 31, 2017 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 39 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 39 |
| | $ | 373 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 373 |
| $ | 168 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 168 |
| | $ | 656 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 656 |
|
NDT fund investments | | | | | | | | |
| | | | | | | | | |
| | | | | | | | |
| | | | | | | | | |
|
Cash equivalents(b) | | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
| | 135 |
| | 85 |
| | — |
| | — |
| | 220 |
|
Equities | | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
| | 4,163 |
| | 915 |
| | — |
| | 2,176 |
| | 7,254 |
|
Fixed income | |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
Corporate debt | | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
| | — |
| | 1,614 |
| | 251 |
| | — |
| | 1,865 |
|
U.S. Treasury and agencies | | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
| | 1,917 |
| | 52 |
| | — |
| | — |
| | 1,969 |
|
Foreign governments | | — |
| | 82 |
| | — |
| | — |
| | 82 |
| | — |
| | 82 |
| | — |
| | — |
| | 82 |
|
State and municipal debt | | — |
| | 263 |
| | — |
| | — |
| | 263 |
| | — |
| | 263 |
| | — |
| | — |
| | 263 |
|
Other(c) | | — |
| | 47 |
| | — |
| | 510 |
| | 557 |
| | — |
| | 47 |
| | — |
| | 510 |
| | 557 |
|
Fixed income subtotal | | 1,917 |
|
| 2,058 |
|
| 251 |
|
| 510 |
|
| 4,736 |
|
| 1,917 |
|
| 2,058 |
|
| 251 |
|
| 510 |
|
| 4,736 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Generation | | Exelon | Generation | | Exelon |
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 | |
Cash equivalents(b) | 110 |
| | 19 |
| | — |
| | — |
| | 129 |
| | 110 |
| | 19 |
| | — |
| | — |
| | 129 |
| |
Equities | 3,551 |
| | 452 |
| | — |
| | 2,011 |
| | 6,014 |
| | 3,551 |
| | 452 |
| | — |
| | 2,011 |
| | 6,014 |
| |
Fixed income |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
| |
Corporate debt | — |
| | 1,554 |
| | 250 |
| | — |
| | 1,804 |
| | — |
| | 1,554 |
| | 250 |
| | — |
| | 1,804 |
| |
U.S. Treasury and agencies | 1,291 |
| | 29 |
| | — |
| | — |
| | 1,320 |
| | 1,291 |
| | 29 |
| | — |
| | — |
| | 1,320 |
| |
Foreign governments | — |
| | 37 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
| |
State and municipal debt | — |
| | 264 |
| | — |
| | — |
| | 264 |
| | — |
| | 264 |
| | — |
| | — |
| | 264 |
| |
Other(c) | — |
| | 59 |
| | — |
| | 493 |
| | 552 |
| | — |
| | 59 |
| | — |
| | 493 |
| | 552 |
| |
Fixed income subtotal | 1,291 |
|
| 1,943 |
|
| 250 |
|
| 493 |
|
| 3,977 |
|
| 1,291 |
|
| 1,943 |
|
| 250 |
|
| 493 |
|
| 3,977 |
| |
As of December 31, 2017 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Middle market lending | — |
| | — |
| | 427 |
| | 71 |
| | 498 |
| | — |
| | — |
| | 427 |
| | 71 |
| | 498 |
| — |
| | — |
| | 397 |
| | 131 |
| | 528 |
| | — |
| | — |
| | 397 |
| | 131 |
| | 528 |
|
Private equity | — |
| | — |
| | — |
| | 148 |
| | 148 |
| | — |
| | — |
| | — |
| | 148 |
| | 148 |
| — |
| | — |
| | — |
| | 222 |
| | 222 |
| | — |
| | — |
| | — |
| | 222 |
| | 222 |
|
Real estate | — |
| | — |
| | — |
| | 326 |
| | 326 |
| | — |
| | — |
| | — |
| | 326 |
| | 326 |
| — |
| | — |
| | — |
| | 471 |
| | 471 |
| | — |
| | — |
| | — |
| | 471 |
| | 471 |
|
NDT fund investments subtotal(d) | 4,952 |
|
| 2,414 |
|
| 677 |
|
| 3,049 |
|
| 11,092 |
|
| 4,952 |
|
| 2,414 |
|
| 677 |
|
| 3,049 |
|
| 11,092 |
| 6,215 |
|
| 3,058 |
|
| 648 |
|
| 3,510 |
|
| 13,431 |
|
| 6,215 |
|
| 3,058 |
|
| 648 |
|
| 3,510 |
|
| 13,431 |
|
Pledged assets for Zion Station decommissioning |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
Cash equivalents | 11 |
| | — |
| | — |
| | — |
| | 11 |
| | 11 |
| | — |
| | — |
| | — |
| | 11 |
| 2 |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
Equities | — |
| | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Fixed Income - U.S. Treasury and agencies | 16 |
| | 1 |
| | — |
| | — |
| | 17 |
| | 16 |
| | 1 |
| | — |
| | — |
| | 17 |
| |
Middle market lending | — |
|
| — |
|
| 19 |
| | 64 |
| | 83 |
| | — |
|
| — |
|
| 19 |
| | 64 |
| | 83 |
| — |
|
| — |
|
| 12 |
| | 24 |
| | 36 |
| | — |
|
| — |
|
| 12 |
| | 24 |
| | 36 |
|
Pledged assets for Zion Station decommissioning subtotal | 27 |
|
| 3 |
|
| 19 |
|
| 64 |
|
| 113 |
|
| 27 |
|
| 3 |
|
| 19 |
|
| 64 |
|
| 113 |
| 2 |
|
| 1 |
|
| 12 |
|
| 24 |
|
| 39 |
|
| 2 |
|
| 1 |
|
| 12 |
|
| 24 |
|
| 39 |
|
Rabbi trust investments |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
Cash equivalents | 2 |
| | — |
| | — |
| | — |
| | 2 |
| | 74 |
| | — |
| | — |
| | — |
| | 74 |
| 5 |
| | — |
| | — |
| | — |
| | 5 |
| | 77 |
| | — |
| | — |
| | — |
| | 77 |
|
Mutual funds | 19 |
| | — |
| | — |
| | — |
| | 19 |
| | 50 |
| | — |
| | — |
| | — |
| | 50 |
| 23 |
| | — |
| | — |
| | — |
| | 23 |
| | 58 |
| | — |
| | — |
| | — |
| | 58 |
|
Fixed income | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 16 |
| | — |
| | — |
| | 16 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 12 |
| | — |
| | — |
| | 12 |
|
Life insurance contracts | — |
| | 18 |
| | — |
| | — |
| | 18 |
| | — |
| | 64 |
| | 20 |
| | — |
| | 84 |
| — |
| | 22 |
| | — |
| | — |
| | 22 |
| | — |
| | 71 |
| | 22 |
| | — |
| | 93 |
|
Rabbi trust investments subtotal | 21 |
|
| 18 |
|
| — |
|
| — |
|
| 39 |
|
| 124 |
|
| 80 |
|
| 20 |
|
| — |
|
| 224 |
| |
Rabbi trust investments subtotal(f) | | 28 |
|
| 22 |
|
| — |
|
| — |
|
| 50 |
|
| 135 |
|
| 83 |
|
| 22 |
|
| — |
|
| 240 |
|
Commodity derivative assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Economic hedges | 1,356 |
| | 2,505 |
| | 1,229 |
| | — |
| | 5,090 |
| | 1,358 |
| | 2,505 |
| | 1,229 |
| | — |
| | 5,092 |
| 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
| | 557 |
| | 2,378 |
| | 1,290 |
| | — |
| | 4,225 |
|
Proprietary trading | 3 |
| | 50 |
| | 23 |
| | — |
| | 76 |
| | 3 |
| | 50 |
| | 23 |
| | — |
| | 76 |
| 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
| | 2 |
| | 31 |
| | 35 |
| | — |
| | 68 |
|
Effect of netting and allocation of collateral(e)(f) | (1,162 | ) | | (2,142 | ) | | (481 | ) | | — |
| | (3,785 | ) | | (1,164 | ) | | (2,142 | ) | | (481 | ) | | — |
| | (3,787 | ) | |
Effect of netting and allocation of collateral(e) | | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) | | (585 | ) | | (1,769 | ) | | (635 | ) | | — |
| | (2,989 | ) |
Commodity derivative assets subtotal | 197 |
|
| 413 |
|
| 771 |
|
| — |
|
| 1,381 |
|
| 197 |
|
| 413 |
|
| 771 |
|
| — |
|
| 1,381 |
| (26 | ) |
| 640 |
|
| 690 |
|
| — |
|
| 1,304 |
|
| (26 | ) |
| 640 |
|
| 690 |
|
| — |
|
| 1,304 |
|
Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | | — |
| | 3 |
| | — |
| | — |
| | 3 |
| | — |
| | 6 |
| | — |
| | — |
| | 6 |
|
Economic hedges | | — |
| | 10 |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | 10 |
|
Effect of netting and allocation of collateral | | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) | | (2 | ) | | (5 | ) | | — |
| | — |
| | (7 | ) |
Interest rate and foreign currency derivative assets subtotal | | (2 | ) |
| 8 |
|
| — |
|
| — |
|
| 6 |
|
| (2 | ) |
| 11 |
|
| — |
|
| — |
|
| 9 |
|
Other investments | | — |
|
| — |
|
| 37 |
| | — |
| | 37 |
| | — |
| | — |
| | 37 |
| | — |
| | 37 |
|
Total assets | | 6,385 |
|
| 3,729 |
|
| 1,387 |
|
| 3,534 |
|
| 15,035 |
|
| 6,980 |
|
| 3,793 |
|
| 1,409 |
|
| 3,534 |
|
| 15,716 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Generation | | Exelon | Generation | | Exelon |
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 | |
Interest rate and foreign currency derivative assets | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 16 |
| | — |
| | — |
| | 16 |
| |
Economic hedges | — |
| | 28 |
| | — |
| | — |
| | 28 |
| | — |
| | 28 |
| | — |
| | — |
| | 28 |
| |
Proprietary trading | 3 |
| | 2 |
| | — |
| | — |
| | 5 |
| | 3 |
| | 2 |
| | — |
| | — |
| | 5 |
| |
Effect of netting and allocation of collateral | (2 | ) | | (19 | ) | | — |
| | — |
| | (21 | ) | | (2 | ) | | (19 | ) | | — |
| | — |
| | (21 | ) | |
Interest rate and foreign currency derivative assets subtotal | 1 |
|
| 11 |
|
| — |
|
| — |
|
| 12 |
|
| 1 |
|
| 27 |
|
| — |
|
| — |
|
| 28 |
| |
Other investments | — |
|
| — |
|
| 42 |
| | — |
| | 42 |
| | — |
| | — |
| | 42 |
| | — |
| | 42 |
| |
Total assets | 5,237 |
|
| 2,859 |
|
| 1,509 |
|
| 3,113 |
|
| 12,718 |
|
| 5,674 |
|
| 2,937 |
|
| 1,529 |
|
| 3,113 |
|
| 13,253 |
| |
As of December 31, 2017 | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
Commodity derivative liabilities |
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
| |
|
|
|
|
| | | |
|
Economic hedges | (1,267 | ) | | (2,378 | ) | | (794 | ) | | — |
| | (4,439 | ) | | (1,267 | ) | | (2,378 | ) | | (1,052 | ) | | — |
| | (4,697 | ) | (712 | ) | | (2,226 | ) | | (845 | ) | | — |
| | (3,783 | ) | | (713 | ) | | (2,226 | ) | | (1,101 | ) | | — |
| | (4,040 | ) |
Proprietary trading | (3 | ) | | (50 | ) | | (26 | ) | | — |
| | (79 | ) | | (3 | ) | | (50 | ) | | (26 | ) | | — |
| | (79 | ) | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) | | (2 | ) | | (42 | ) | | (9 | ) | | — |
| | (53 | ) |
Effect of netting and allocation of collateral(e)(f) | 1,233 |
| | 2,339 |
| | 542 |
| | — |
| | 4,114 |
| | 1,233 |
| | 2,339 |
| | 542 |
| | — |
| | 4,114 |
| |
Effect of netting and allocation of collateral(e) | | 650 |
| | 2,089 |
| | 716 |
| | — |
| | 3,455 |
| | 651 |
| | 2,089 |
| | 716 |
| | — |
| | 3,456 |
|
Commodity derivative liabilities subtotal | (37 | ) |
| (89 | ) |
| (278 | ) |
| — |
|
| (404 | ) |
| (37 | ) |
| (89 | ) |
| (536 | ) |
| — |
|
| (662 | ) | (64 | ) |
| (179 | ) |
| (138 | ) |
| — |
|
| (381 | ) |
| (64 | ) |
| (179 | ) |
| (394 | ) |
| — |
|
| (637 | ) |
Interest rate and foreign currency derivative liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Derivatives designated as hedging instruments | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) | | — |
| | (10 | ) | | — |
| | — |
| | (10 | ) | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) |
Economic hedges | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) | | — |
| | (21 | ) | | — |
| | — |
| | (21 | ) | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) | | (1 | ) | | (8 | ) | | — |
| | — |
| | (9 | ) |
Proprietary trading | (4 | ) | | — |
| | — |
| | — |
| | (4 | ) | | (4 | ) | | — |
| | — |
| | — |
| | (4 | ) | |
Effect of netting and allocation of collateral | 4 |
| | 19 |
| | — |
| | — |
| | 23 |
| | 4 |
| | 19 |
| | — |
| | — |
| | 23 |
| 2 |
| | 5 |
| | — |
| | — |
| | 7 |
| | 2 |
| | 5 |
| | — |
| | — |
| | 7 |
|
Interest rate and foreign currency derivative liabilities subtotal | — |
|
| (12 | ) |
| — |
|
| — |
|
| (12 | ) |
| — |
|
| (12 | ) |
| — |
|
| — |
|
| (12 | ) | 1 |
|
| (5 | ) |
| — |
|
| — |
|
| (4 | ) |
| 1 |
|
| (5 | ) |
| — |
|
| — |
|
| (4 | ) |
Deferred compensation obligation | — |
|
| (34 | ) |
| — |
| | — |
| | (34 | ) | | — |
|
| (136 | ) |
| — |
| | — |
| | (136 | ) | — |
|
| (38 | ) |
| — |
| | — |
| | (38 | ) | | — |
|
| (145 | ) |
| — |
| | — |
| | (145 | ) |
Total liabilities | (37 | ) |
| (135 | ) |
| (278 | ) |
| — |
|
| (450 | ) |
| (37 | ) |
| (237 | ) |
| (536 | ) |
| — |
|
| (810 | ) | (63 | ) |
| (222 | ) |
| (138 | ) |
| — |
|
| (423 | ) |
| (63 | ) |
| (329 | ) |
| (394 | ) |
| — |
|
| (786 | ) |
Total net assets | $ | 5,200 |
|
| $ | 2,724 |
|
| $ | 1,231 |
|
| $ | 3,113 |
|
| $ | 12,268 |
|
| $ | 5,637 |
|
| $ | 2,700 |
|
| $ | 993 |
|
| $ | 3,113 |
|
| $ | 12,443 |
| $ | 6,322 |
|
| $ | 3,507 |
|
| $ | 1,249 |
|
| $ | 3,534 |
|
| $ | 14,612 |
|
| $ | 6,917 |
|
| $ | 3,464 |
|
| $ | 1,015 |
|
| $ | 3,534 |
|
| $ | 14,930 |
|
__________
| |
(a) | Generation excludes cash of $259$283 million and $252$259 million at December 31, 20172018 and 20162017 and restricted cash of $127$39 million and $157$127 million at December 31, 20172018 and 2016.2017. Exelon excludes cash of $389$458 million and $360$389 million at December 31, 20172018 and 20162017 and restricted cash of $145$80 million and $180$145 million at December 31, 20172018 and 20162017 and includes long-term restricted cash of $85$185 million and $25$85 million at December 31, 20172018 and 2016,2017, which is reported in Other deferred debits onin the Consolidated Balance Sheets. |
| |
(b) | Includes $77$50 million and $29$77 million of cash received from outstanding repurchase agreements at December 31, 20172018 and 2016,2017, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(c) | Includes derivative instruments of $44 million and less than $1 million and $(2) million, which have a total notional amount of $811$1,432 million and $933$811 million at December 31, 20172018 and 2016,2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss. |
| |
(d) | Excludes net liabilities of $82$130 million and $31$82 million at December 31, 20172018 and 2016,2017, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less. |
| |
(e) | Excludes net assets of less than $1 million at December 31, 2018 and 2017. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases. |
| |
(f) | The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively. |
| |
(g) | Collateral posted/(received) from counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018. Collateral posted/(received) from counterparties totaled $65 million, $320 million and $81 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2017. Collateral posted/(received) from counterparties totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016. |
| |
(f)(h) | Of the collateral posted/(received), $(117)$(94) million and $(158)$(117) million represents variation margin on the exchanges as of December 31, 20172018 and 2016,2017, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $72 millionas of December 31, 2018. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2018.
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value onin ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 20172018 and 2016:2017:
| | | ComEd | | PECO | | BGE | ComEd | | PECO | | BGE |
As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | |
As of December 31, 2018 | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 98 |
|
| $ | — |
|
| $ | — |
| | $ | 98 |
| | $ | 228 |
|
| $ | — |
|
| $ | — |
| | $ | 228 |
| | $ | — |
|
| $ | — |
|
| $ | — |
| | $ | — |
| $ | 209 |
|
| $ | — |
|
| $ | — |
| | $ | 209 |
| | $ | 111 |
|
| $ | — |
|
| $ | — |
| | $ | 111 |
| | $ | 4 |
|
| $ | — |
|
| $ | — |
| | $ | 4 |
|
Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
| — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
|
Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
| — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
|
Total assets | 98 |
|
| — |
|
| — |
|
| 98 |
|
| 235 |
|
| 10 |
|
| — |
|
| 245 |
|
| 6 |
|
| — |
|
| — |
|
| 6 |
| 209 |
|
| — |
|
| — |
|
| 209 |
|
| 118 |
|
| 10 |
|
| — |
|
| 128 |
|
| 10 |
|
| — |
|
| — |
|
| 10 |
|
Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
Deferred compensation obligation | — |
|
| (8 | ) |
| — |
| | (8 | ) | | — |
|
| (11 | ) |
| — |
| | (11 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) | — |
|
| (6 | ) |
| — |
| | (6 | ) | | — |
|
| (10 | ) |
| — |
| | (10 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) |
Mark-to-market derivative liabilities(b)(c) | — |
|
| — |
|
| (256 | ) | | (256 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| — |
|
| — |
|
| (249 | ) | | (249 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
|
Total liabilities | — |
|
| (8 | ) |
| (256 | ) |
| (264 | ) |
| — |
|
| (11 | ) |
| — |
|
| (11 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) | — |
|
| (6 | ) |
| (249 | ) |
| (255 | ) |
| — |
|
| (10 | ) |
| — |
|
| (10 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) |
Total net assets (liabilities) | $ | 98 |
|
| $ | (8 | ) |
| $ | (256 | ) |
| $ | (166 | ) |
| $ | 235 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 234 |
|
| $ | 6 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 1 |
| $ | 209 |
|
| $ | (6 | ) |
| $ | (249 | ) |
| $ | (46 | ) |
| $ | 118 |
|
| $ | — |
|
| $ | — |
|
| $ | 118 |
|
| $ | 10 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 5 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | ComEd | | PECO | | BGE | ComEd | | PECO | | BGE |
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 | |
As of December 31, 2017 | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 20 |
|
| $ | — |
|
| $ | — |
| | $ | 20 |
| | $ | 45 |
|
| $ | — |
|
| $ | — |
| | $ | 45 |
| | $ | 36 |
|
| $ | — |
|
| $ | — |
| | $ | 36 |
| $ | 98 |
|
| $ | — |
|
| $ | — |
| | $ | 98 |
| | $ | 228 |
|
| $ | — |
|
| $ | — |
| | $ | 228 |
| | $ | — |
|
| $ | — |
|
| $ | — |
| | $ | — |
|
Rabbi trust investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Mutual funds | — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 4 |
|
| — |
|
| — |
| | 4 |
| — |
|
| — |
|
| — |
| | — |
| | 7 |
|
| — |
|
| — |
| | 7 |
| | 6 |
|
| — |
|
| — |
| | 6 |
|
Life insurance contracts | — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 10 |
| | — |
| | 10 |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 4 |
| | — |
| | — |
| | 4 |
| — |
| | — |
| | — |
| | — |
| | 7 |
| | 10 |
| | — |
| | 17 |
| | 6 |
| | — |
| | — |
| | 6 |
|
Total assets | 20 |
|
| — |
|
| — |
|
| 20 |
|
| 52 |
|
| 10 |
|
| — |
|
| 62 |
|
| 40 |
|
| — |
|
| — |
|
| 40 |
| 98 |
|
| — |
|
| — |
|
| 98 |
|
| 235 |
|
| 10 |
|
| — |
|
| 245 |
|
| 6 |
|
| — |
|
| — |
|
| 6 |
|
Liabilities |
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
|
|
|
|
| |
| |
|
|
|
|
| |
| |
|
|
|
|
| |
|
Deferred compensation obligation | — |
|
| (8 | ) |
| — |
| | (8 | ) | | — |
|
| (11 | ) |
| — |
| | (11 | ) | | — |
|
| (4 | ) |
| — |
| | (4 | ) | — |
|
| (8 | ) |
| — |
| | (8 | ) | | — |
|
| (11 | ) |
| — |
| | (11 | ) | | — |
|
| (5 | ) |
| — |
| | (5 | ) |
Mark-to-market derivative liabilities(b)(c) | — |
|
| — |
|
| (258 | ) | | (258 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
| — |
|
| — |
|
| (256 | ) | | (256 | ) | | — |
|
| — |
|
| — |
| | — |
| | — |
|
| — |
|
| — |
| | — |
|
Total liabilities | — |
|
| (8 | ) |
| (258 | ) |
| (266 | ) |
| — |
|
| (11 | ) |
| — |
|
| (11 | ) |
| — |
|
| (4 | ) |
| — |
|
| (4 | ) | — |
|
| (8 | ) |
| (256 | ) |
| (264 | ) |
| — |
|
| (11 | ) |
| — |
|
| (11 | ) |
| — |
|
| (5 | ) |
| — |
|
| (5 | ) |
Total net assets (liabilities) | $ | 20 |
|
| $ | (8 | ) |
| $ | (258 | ) |
| $ | (246 | ) |
| $ | 52 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 51 |
|
| $ | 40 |
|
| $ | (4 | ) |
| $ | — |
|
| $ | 36 |
| $ | 98 |
|
| $ | (8 | ) |
| $ | (256 | ) |
| $ | (166 | ) |
| $ | 235 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 234 |
|
| $ | 6 |
|
| $ | (5 | ) |
| $ | — |
|
| $ | 1 |
|
__________
| |
(a) | ComEd excludes cash of $45$93 million and $36$45 million at December 31, 20172018 and 20162017 and restricted cash of $2$28 million at December 31, 20162018 and includes long-term restricted cash of $62$166 million and $62 millionat December 31, 2018 and December 31, 2017, which is reported in Other deferred debits onin the Consolidated Balance Sheets. PECO excludes cash of $47$24 million and $22$47 million at December 31, 20172018 and 2016.2017. BGE excludes cash of $17$7 million and $13$17 million at December 31, 2018 and 2017 and 2016 and restricted cash of $1 million at December 31, 2017 and includes long-term restricted cash of $2 million and $1 millionat December 31, 2016, which is reported in Other deferred debits on the Consolidated Balance Sheets.2018 and December 31, 2017. |
| |
(b) | The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the years ended December 31, 2018 and December 31, 2017. |
| |
(c) | The Level 3 balance consists of the current and noncurrent liability of $26 million and $223 million, respectively, at December 31, 2018, and $21 million and $235 million, respectively, at December 31, 2017, and $19 million and $239 million, respectively, at December 31, 2016, related to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI, Pepco, DPL and ACE
The following tables present assets and liabilities measured and recorded at fair value onin PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 20172018 and 2016:2017:
| | | Successor | |
| As of December 31, 2017 | | As of December 31, 2016 | As of December 31, 2018 | | As of December 31, 2017 |
PHI | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 83 |
| | $ | 217 |
| | $ | — |
| | $ | — |
| | $ | 217 |
| $ | 147 |
| | $ | — |
| | $ | — |
| | $ | 147 |
| | $ | 83 |
| | $ | — |
| | $ | — |
| | $ | 83 |
|
Mark-to-market derivative assets(b) | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| |
Effect of netting and allocation of collateral | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | |
Mark-to-market derivative assets subtotal | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Rabbi trust investments | | | | | | |
| | | | | | | |
|
| | | | | | |
| | | | | | | |
|
|
Cash equivalents | 72 |
| | — |
| | — |
| | 72 |
| | 73 |
| | — |
| | — |
| | 73 |
| 42 |
| | — |
| | — |
| | 42 |
| | 72 |
| | — |
| | — |
| | 72 |
|
Mutual Funds | | 13 |
| | — |
| | — |
| | 13 |
| | — |
| | — |
| | — |
| | — |
|
Fixed income | — |
| | 12 |
| | — |
| | 12 |
| | — |
| | 16 |
| | — |
| | 16 |
| — |
| | 15 |
| | — |
| | 15 |
| | — |
| | 12 |
| | — |
| | 12 |
|
Life insurance contracts | — |
| | 23 |
| | 22 |
| | 45 |
| | — |
| | 22 |
| | 20 |
| | 42 |
| — |
| | 22 |
| | 38 |
| | 60 |
| | — |
| | 23 |
| | 22 |
| | 45 |
|
Rabbi trust investments subtotal | 72 |
|
| 35 |
|
| 22 |
|
| 129 |
|
| | 73 |
|
| 38 |
|
| 20 |
|
| 131 |
| |
Rabbi trust investments subtotal(b) | | 55 |
|
| 37 |
|
| 38 |
|
| 130 |
|
| | 72 |
|
| 35 |
|
| 22 |
|
| 129 |
|
Total assets | 155 |
|
| 35 |
|
| 22 |
|
| 212 |
|
| 290 |
|
| 38 |
|
| 20 |
|
| 348 |
| 202 |
|
| 37 |
|
| 38 |
|
| 277 |
|
| 155 |
|
| 35 |
|
| 22 |
|
| 212 |
|
Liabilities | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | |
|
|
Deferred compensation obligation | — |
| | (25 | ) | | — |
| | (25 | ) | | — |
| | (28 | ) | | — |
| | (28 | ) | — |
| | (21 | ) | | — |
| | (21 | ) | | — |
| | (25 | ) | | — |
| | (25 | ) |
Mark-to-market derivative liabilities(b) | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| |
Mark-to-market derivative liabilities | | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) |
Effect of netting and allocation of collateral | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
Mark-to-market derivative liabilities subtotal | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total liabilities | — |
|
| (25 | ) |
| — |
|
| (25 | ) |
| — |
|
| (28 | ) |
| — |
|
| (28 | ) | — |
|
| (21 | ) |
| — |
|
| (21 | ) |
| — |
|
| (25 | ) |
| — |
|
| (25 | ) |
Total net assets | $ | 155 |
|
| $ | 10 |
|
| $ | 22 |
|
| $ | 187 |
|
| $ | 290 |
|
| $ | 10 |
|
| $ | 20 |
|
| $ | 320 |
| $ | 202 |
|
| $ | 16 |
|
| $ | 38 |
|
| $ | 256 |
|
| $ | 155 |
|
| $ | 10 |
|
| $ | 22 |
|
| $ | 187 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
As of December 31, 2018 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 38 |
| | $ | — |
| | $ | — |
| | $ | 38 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | 16 |
| | $ | 23 |
| | $ | — |
| | $ | — |
| | $ | 23 |
|
Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
|
Cash equivalents | 41 |
| | — |
| | — |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fixed income | — |
| | 5 |
| | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Life insurance contracts | — |
| | 22 |
| | 37 |
| | 59 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | 41 |
|
| 27 |
|
| 37 |
|
| 105 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total assets | 79 |
|
| 27 |
|
| 37 |
|
| 143 |
|
| 16 |
|
| — |
|
| — |
|
| 16 |
|
| 23 |
|
| — |
|
| — |
|
| 23 |
|
Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Deferred compensation obligation | — |
| | (3 | ) | | — |
| | (3 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
Total liabilities | — |
|
| (3 | ) |
| — |
|
| (3 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
Total net assets (liabilities) | $ | 79 |
|
| $ | 24 |
|
| $ | 37 |
|
| $ | 140 |
|
| $ | 16 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 15 |
|
| $ | 23 |
|
| $ | — |
|
| $ | — |
|
| $ | 23 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Pepco | | DPL | | ACE | Pepco | | DPL | | ACE |
As of December 31, 2017 | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cash equivalents(a) | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| $ | 36 |
| | $ | — |
| | $ | — |
| | $ | 36 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
| | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
|
Cash equivalents | 44 |
| | — |
| | — |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 44 |
| | — |
| | — |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fixed income | — |
| | 12 |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | 12 |
| | — |
| | 12 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Life insurance contracts | — |
| | 23 |
| | 22 |
| | 45 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | 23 |
| | 22 |
| | 45 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal(b) | 44 |
|
| 35 |
|
| 22 |
|
| 101 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| 44 |
|
| 35 |
|
| 22 |
|
| 101 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total assets | 80 |
|
| 35 |
|
| 22 |
|
| 137 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 29 |
|
| — |
|
| — |
|
| 29 |
| 80 |
|
| 35 |
|
| 22 |
|
| 137 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| 29 |
|
| — |
|
| — |
|
| 29 |
|
Liabilities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Deferred compensation obligation | — |
| | (4 | ) | | — |
| | (4 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| — |
| | (4 | ) | | — |
| | (4 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
Mark-to-market derivative liabilities (b) | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
Effect of netting and allocation of collateral | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
|
Mark-to-market derivative liabilities subtotal | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total liabilities | — |
|
| (4 | ) |
| — |
|
| (4 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| (4 | ) |
| — |
|
| (4 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
Total net assets (liabilities) | $ | 80 |
|
| $ | 31 |
|
| $ | 22 |
|
| $ | 133 |
|
| $ | — |
|
| $ | (1 | ) |
| $ | — |
|
| $ | (1 | ) |
| $ | 29 |
|
| $ | — |
|
| $ | — |
|
| $ | 29 |
| $ | 80 |
|
| $ | 31 |
|
| $ | 22 |
|
| $ | 133 |
|
| $ | — |
|
| $ | (1 | ) |
| $ | — |
|
| $ | (1 | ) |
| $ | 29 |
|
| $ | — |
|
| $ | — |
|
| $ | 29 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pepco | | DPL | | ACE |
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) | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | 33 |
| | $ | 42 |
| | $ | — |
| | $ | — |
| | $ | 42 |
| | $ | 130 |
| | $ | — |
| | $ | — |
| | $ | 130 |
|
Mark-to-market derivative assets(b) | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
Effect of netting and allocation of collateral | — |
| | — |
| | — |
| | — |
| | (2 | ) | | — |
| | — |
| | (2 | ) | | — |
| | — |
| | — |
| | — |
|
Mark-to-market derivative assets subtotal | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments | | | | | | |
|
| | | | | | | |
|
| | | | | | | |
|
|
Cash equivalents | 43 |
| | — |
| | — |
| | 43 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fixed income | — |
| | 16 |
| | — |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Life insurance contracts | — |
| | 22 |
| | 19 |
| | 41 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Rabbi trust investments subtotal | 43 |
|
| 38 |
|
| 19 |
|
| 100 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Total assets | 76 |
|
| 38 |
|
| 19 |
|
| 133 |
|
| 42 |
|
| — |
|
| — |
|
| 42 |
|
| 130 |
|
| — |
|
| — |
|
| 130 |
|
Liabilities | | | | | | | | | | | | | | | | | | | | | | | |
Deferred compensation obligation | — |
| | (5 | ) | | — |
| | (5 | ) | | — |
| | (1 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | — |
|
Total liabilities | — |
|
| (5 | ) |
| — |
|
| (5 | ) |
| — |
|
| (1 | ) |
| — |
|
| (1 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
Total net assets (liabilities) | $ | 76 |
|
| $ | 33 |
|
| $ | 19 |
|
| $ | 128 |
|
| $ | 42 |
|
| $ | (1 | ) |
| $ | — |
|
| $ | 41 |
|
| $ | 130 |
|
| $ | — |
|
| $ | — |
|
| $ | 130 |
|
_________________
| |
(a) | PHI excludes cash of $12$39 million and $19$12 million at December 31, 20172018 and 20162017 and includes long term restricted cash of $23$19 million and $23 millionat both December 31, 20172018 and 20162017 which is reported in Other deferred debits onin the Consolidated Balance Sheets. Pepco excludes cash of $4 million and $9 million at December 31, 2017 and 2016. DPL excludes cash of $2$15 million and $4 million at December 31, 20172018 and 2016.2017. DPL excludes cash of $8 million and $2 million at December 31, 2018 and 2017. ACE excludes cash of $2$7 million and $3$2 million at December 31, 20172018 and 20162017 and includes long-term restricted cash of $23$19 million and $23 millionat both December 31, 2018 and 2017 at December 31, 2018 and 20162017 which is reported in Other deferred debits onin the Consolidated Balance Sheets. |
| |
(b) | Represents natural gas futures purchased by DPL as partThe amount of a natural gas hedging program approved byunrealized gains/(losses) at PHI totaled $1 million for the DPSC.years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for the years ended December 31, 2018 and 2017, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 20172018 and 2016:2017:
| | | | | | | | | | | | | | | Successor | | | | | Generation | | ComEd | | PHI | | | | Exelon |
| Generation | | ComEd | | PHI | | | | Exelon | |
For the year ended December 31, 2017 | NDT Fund Investments | | Pledged Assets for Zion Station Decommissioning | | Mark-to-Market Derivatives | | Other Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation | | Total | |
Balance as of January 1, 2017 | $ | 677 |
|
| $ | 19 |
| | $ | 493 |
|
| $ | 42 |
| | $ | 1,231 |
| | $ | (258 | ) | | $ | 20 |
| | $ | — |
| | $ | 993 |
| |
For the year ended December 31, 2018 | | NDT Fund Investments | | Pledged Assets for Zion Station Decommissioning | | Mark-to-Market Derivatives | | Other Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts(c) | | Eliminated in Consolidation | | Total |
Balance as of January 1, 2018 | | $ | 648 |
|
| $ | 12 |
| | $ | 552 |
|
| $ | 37 |
| | $ | 1,249 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
| | $ | 1,015 |
|
Total realized / unrealized gains (losses) |
|
|
| |
|
| | |
|
| | | | | | | |
|
|
|
| |
|
| | |
|
| | | | | | | |
|
Included in net income | 3 |
|
| — |
| | (90 | ) | (a) | 3 |
| | (84 | ) | | — |
| | 3 |
| | — |
| | (81 | ) | — |
|
| — |
| | (105 | ) | (a) | 3 |
| | (102 | ) | | — |
| | 4 |
| | — |
| | (98 | ) |
Included in noncurrent payables to affiliates | 6 |
|
| — |
| | — |
|
| — |
| | 6 |
| | — |
| | — |
| | (6 | ) | | — |
| (1 | ) |
| — |
| | — |
|
| — |
| | (1 | ) | | — |
| | — |
| | 1 |
| | — |
|
Included in payable for Zion Station decommissioning | — |
|
| (8 | ) | | — |
|
| — |
| | (8 | ) | | — |
| | — |
| | — |
| | (8 | ) | — |
|
| 7 |
| | — |
|
| — |
| | 7 |
| | — |
| | — |
| | — |
| | 7 |
|
Included in regulatory assets/liabilities | — |
|
| — |
| | — |
| | — |
| | — |
| | 2 |
| (b) | — |
| | 6 |
| | 8 |
| — |
|
| — |
| | — |
| | — |
| | — |
| | 7 |
| (b) | — |
| | (1 | ) | | 6 |
|
Change in collateral | — |
|
| — |
| | 20 |
|
| — |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
| — |
|
| — |
| | (5 | ) |
| — |
| | (5 | ) | | — |
| | — |
| | — |
| | (5 | ) |
Purchases, sales, issuances and settlements | |
| | | |
| | |
| | | | | | | |
| |
| | | |
| | |
| | | | | | | |
|
Purchases | 64 |
|
| 1 |
| | 178 |
| | 5 |
| | 248 |
| | — |
| | — |
| | — |
| | 248 |
| 36 |
|
| 1 |
| | 190 |
| (e) | 4 |
| | 231 |
| | — |
| | — |
| | — |
| | 231 |
|
Sales | — |
|
| — |
| | (16 | ) |
| — |
| | (16 | ) | | — |
| | — |
| | — |
| | (16 | ) | — |
|
| (20 | ) | | (4 | ) |
| — |
| | (24 | ) | | — |
| | — |
| | — |
| | (24 | ) |
Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Settlements | (102 | ) |
| — |
| | (8 | ) | (c) | — |
| | (110 | ) | | — |
| | — |
| | — |
| | (110 | ) | (140 | ) |
| — |
| | 5 |
|
| — |
| | (135 | ) | | — |
| | 12 |
| | — |
| | (123 | ) |
Transfers into Level 3 | — |
|
| — |
| | (6 | ) |
| — |
| | (6 | ) | | — |
| | — |
| | — |
| | (6 | ) | — |
|
| — |
| | (22 | ) | (d) | — |
| | (22 | ) | | — |
| | — |
| | — |
| | (22 | ) |
Transfers out of Level 3 | — |
|
| — |
| | (50 | ) |
| (11 | ) | | (61 | ) | | — |
| | — |
| | — |
| | (61 | ) | — |
|
| — |
| | (36 | ) | (d) | (2 | ) | | (38 | ) | | — |
| | — |
| | — |
| | (38 | ) |
Other miscellaneous | — |
| | — |
| | 31 |
| (d) | (2 | ) | | 29 |
| | — |
| | — |
| | — |
| | 29 |
| — |
| | — |
| | — |
|
|
|
| | — |
| | — |
| | — |
| | — |
| | — |
|
Balance as of December 31, 2017 | $ | 648 |
|
| $ | 12 |
| | $ | 552 |
|
| $ | 37 |
|
| $ | 1,249 |
| | $ | (256 | ) |
| $ | 22 |
|
| $ | — |
| | $ | 1,015 |
| |
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2017 | $ | 1 |
| | $ | — |
| | $ | 254 |
| | $ | 3 |
| | $ | 258 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 261 |
| |
Balance as of December 31, 2018 | | $ | 543 |
|
| $ | — |
| | $ | 575 |
|
| $ | 42 |
|
| $ | 1,160 |
| | $ | (249 | ) |
| $ | 38 |
|
| $ | — |
| | $ | 949 |
|
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2018 | | $ | (5 | ) | | $ | — |
| | $ | 165 |
| | $ | 3 |
| | $ | 163 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 163 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | | | | Successor | | | | | Generation | | ComEd | | PHI | | | | Exelon |
| Generation | | ComEd | | PHI(f) | | | | Exelon | |
For the year ended December 31, 2016 | NDT Fund Investments | | Pledged Assets for Zion Station Decommissioning | | Mark-to-Market Derivatives | | Other Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts | | Eliminated in Consolidation | | Total | |
Balance as of January 1, 2016 | $ | 670 |
|
| $ | 22 |
| | $ | 1,051 |
|
| $ | 33 |
| | $ | 1,776 |
| | $ | (247 | ) | | $ | — |
| | $ | — |
| | $ | 1,529 |
| |
Included due to merger | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | — |
| | 20 |
| |
For the year ended December 31, 2017 | | NDT Fund Investments | | Pledged Assets for Zion Station Decommissioning | | Mark-to-Market Derivatives | | Other Investments | | Total Generation | | Mark-to-Market Derivatives | | Life Insurance Contracts(c) | | Eliminated in Consolidation | | Total |
Balance as of January 1, 2017 | | $ | 677 |
|
| $ | 19 |
| | $ | 493 |
|
| $ | 42 |
| | $ | 1,231 |
| | $ | (258 | ) | | $ | 20 |
| | $ | — |
| | $ | 993 |
|
Total realized / unrealized gains (losses) |
|
|
| |
|
|
| |
|
| | | | | | | |
|
|
|
|
| |
|
|
| |
|
| | | | | | | |
|
|
Included in net income | 7 |
|
| — |
| | (568 | ) | (a) | 1 |
| | (560 | ) | | — |
| | 3 |
| | — |
| | (557 | ) | 3 |
|
| — |
| | (90 | ) | (a) | 3 |
| | (84 | ) | | — |
| | 3 |
| | — |
| | (81 | ) |
Included in noncurrent payables to affiliates | 16 |
|
| — |
| | — |
| | — |
| | 16 |
| | — |
| | — |
| | (16 | ) | | — |
| 6 |
|
| — |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | (6 | ) | | — |
|
Included in payable for Zion Station decommissioning | | — |
|
| (8 | ) | | — |
| | — |
| | (8 | ) | | — |
| | | | — |
| | (8 | ) |
Included in regulatory assets/liabilities | — |
| | — |
| | — |
| | — |
| | — |
| | (11 | ) | (b) | — |
| | 16 |
| | 5 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| (b) | — |
| | 6 |
| | 8 |
|
Change in collateral | — |
|
| — |
| | (141 | ) | | — |
| | (141 | ) | | — |
| | — |
| | — |
| | (141 | ) | — |
|
| — |
| | 20 |
| | — |
| | 20 |
| | — |
| | — |
| | — |
| | 20 |
|
Purchases, sales, issuances and settlements |
|
|
| |
| |
| |
|
| | | | | | | |
|
|
|
|
| |
| |
| |
|
| | | | | | | |
|
|
Purchases | 143 |
|
| 2 |
| | 342 |
| (e) | 7 |
| | 494 |
| | — |
| | — |
| | — |
| | 494 |
| 64 |
|
| 1 |
| | 178 |
| | 5 |
| | 248 |
| | — |
| | — |
| | — |
| | 248 |
|
Sales | (1 | ) |
| (5 | ) | | (9 | ) |
| — |
| | (15 | ) | | — |
| | — |
| | — |
| | (15 | ) | — |
|
| — |
| | (16 | ) |
| — |
| | (16 | ) | | — |
| | — |
| | — |
| | (16 | ) |
Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (3 | ) | | — |
| | (3 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | (1 | ) |
Settlements | (144 | ) |
| — |
| | — |
|
| — |
| | (144 | ) | | — |
| | — |
| | — |
| | (144 | ) | (102 | ) |
| — |
| | (8 | ) |
| — |
| | (110 | ) | | — |
| | — |
| | — |
| | (110 | ) |
Transfers into Level 3 | — |
|
| — |
| | 1 |
|
| 1 |
| | 2 |
| | — |
| | — |
| | — |
| | 2 |
| — |
|
| — |
| | (6 | ) | (d) | — |
| | (6 | ) | | — |
| | — |
| | — |
| | (6 | ) |
Transfers out of Level 3 | (14 | ) |
| — |
| | (183 | ) |
| — |
| | (197 | ) | | — |
| | — |
| | — |
| | (197 | ) | — |
|
| — |
| | (50 | ) | (d) | (11 | ) | | (61 | ) | | — |
| | — |
| | — |
| | (61 | ) |
Balance as of December 31, 2016 | $ | 677 |
|
| $ | 19 |
| | $ | 493 |
|
| $ | 42 |
|
| $ | 1,231 |
| | $ | (258 | ) | | $ | 20 |
| | $ | — |
| | $ | 993 |
| |
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2016 | $ | 5 |
|
| $ | — |
| | $ | 109 |
|
| $ | — |
| | $ | 114 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | 116 |
| |
Other miscellaneous | | $ | — |
| | $ | — |
| | $ | 31 |
| | $ | (2 | ) | | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
Balance as of December 31, 2017 | | $ | 648 |
|
| $ | 12 |
| | $ | 552 |
|
| $ | 37 |
|
| $ | 1,249 |
| | $ | (256 | ) | | $ | 22 |
| | $ | — |
| | $ | 1,015 |
|
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2017 | | $ | 1 |
|
| $ | — |
| | $ | 254 |
|
| $ | 3 |
| | $ | 258 |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 261 |
|
__________
| |
(a) | Includes a reduction for the reclassification of $352$265 million and $677$352 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 20172018 and 2016,2017, respectively. |
| |
(b) | Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018. Includes $18 million of decreases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017. Includes $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2016. |
| |
(c) | Exelon includes the settlement value for any openThe amounts represented are life insurance contracts that were net settled prior to their scheduled maturity within this line item.at Pepco. |
| |
(d) | As a resultTransfers into and out of Level 3 generally occur when the bankruptcy filingcontract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for EGTP on November 7, 2017, the net mark-to-marketcertain commodity contracts were deconsolidated from Exelon's and Generation's consolidated financial statements.contracts. |
| |
(e) | Includes $168$(19) million of fair value from contracts acquired as a result of portfolio acquisitions.the Everett Marine Terminal acquisition |
| |
(f) | Successor period represents activity from March 24, 2016 to December 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco for the years ended December 31, 2017 and 2016. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| Predecessor |
| January 1, 2016 to March 23, 2016
|
PHI | Preferred Stock | | Life Insurance Contracts |
Beginning Balance | $ | 18 |
| | $ | 19 |
|
Total realized / unrealized (losses) gains | | | |
Included in net income | (18 | ) | | 1 |
|
Ending Balance | $ | — |
|
| $ | 20 |
|
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 |
|
|
| | | | | | | |
| Life Insurance Contracts |
| For the year ended December 31, |
Pepco | 2017 | | 2016 |
Balance as of January 1 | $ | 20 |
| | $ | 19 |
|
Total realized / unrealized gains (losses) | | | |
Included in net income | 3 |
| | 3 |
|
Purchases, sales, issuances and settlements | | | |
Issuances | (1 | ) | | (3 | ) |
Balance as of December 31 | $ | 22 |
| | $ | 19 |
|
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 | $ | 3 |
| | $ | 3 |
|
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 20172018 and 2016:2017:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Successor | | | | | | | | |
| Generation | | PHI | | Exelon |
| Operating Revenues | | Purchased Power and Fuel | | Other, net(a) | | Operating and Maintenance | | Operating Revenues | | Purchased Power and Fuel | | Operating and Maintenance | | Other, net(a) |
Total gains (losses) included in net income for the year ended December 31, 2017 | $ | 28 |
| | $ | (126 | ) | | $ | 6 |
| | $ | 3 |
| | $ | 28 |
| | $ | (126 | ) | | $ | 3 |
| | $ | 6 |
|
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2017 | 290 |
| | (36 | ) | | 4 |
| | 3 |
| | 290 |
| | (36 | ) | | 3 |
| | 4 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | PHI | | Exelon |
| Operating Revenues | | Purchased Power and Fuel | | Other, net | | Operating and Maintenance | | Operating Revenues | | Purchased Power and Fuel | | Operating and Maintenance | | Other, net |
Total (losses) gains included in net income for the year ended December 31, 2018 | $ | (7 | ) | | $ | (93 | ) | | $ | 3 |
| | $ | 4 |
| | $ | (7 | ) | | $ | (93 | ) | | $ | 4 |
| | $ | 3 |
|
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2018 | 144 |
| | 21 |
| | (2 | ) | | — |
| | 144 |
| | 21 |
| | — |
| | (2 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Successor | | | | | | |
| Generation | | PHI(b) | | 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 year ended December 31, 2016 | $ | (477 | ) | | $ | (91 | ) | | $ | 7 |
| | $ | 3 |
| | $ | (477 | ) | | $ | (91 | ) | | $ | 10 |
|
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2016 | 154 |
| | (45 | ) | | 5 |
| | 2 |
| | 154 |
| | (45 | ) | | 7 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | PHI | | Exelon |
| Operating Revenues | | Purchased Power and Fuel | | Other, net | | Operating and Maintenance | | Operating Revenues | | Purchased Power and Fuel | | Operating and Maintenance | | Other, net |
Total gains (losses) included in net income for the year ended December 31, 2017 | $ | 28 |
| | $ | (126 | ) | | $ | 6 |
| | $ | 3 |
| | $ | 28 |
| | $ | (126 | ) | | $ | 3 |
| | $ | 6 |
|
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2017 | 290 |
| | (36 | ) | | 4 |
| | 3 |
| | 290 |
| | (36 | ) | | 3 |
| | 4 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | |
| Predecessor | | | | | | |
| PHI | | Pepco |
| January 1, 2016 to March 23, 2016 | | December 31, 2017 | | December 31, 2017 | | December 31, 2016 |
| Other, net(a) | | Operating and Maintenance | | Other, net(a) |
Total (losses) gains included in net income | $ | (17 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
Change in the unrealized gains (losses) relating to assets and liabilities held | 1 |
| | 3 |
| | — |
| | 3 |
|
__________
| |
(a) | Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation, accrued interest on a convertible promissory note at Generation and the life insurance contracts held by PHI and Pepco. |
| |
(b) | Successor period represents activity from March 24, 2016 to December 31, 2016. See the subsequent table for PHI's predecessor periods, as well as activity for Pepco for the year ended December 31, 2017 and 2016. |
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 original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of 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, 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. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.
Nuclear Decommissioning TrustNDT Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities and Fixed Income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on quoted prices in active markets are categorized in Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
information, such as actual trade information or similar securities. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third-party valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate swaps to manage risk are recorded at fair value. Over the counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over the counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
As of December 31, 2017,2018, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $65$127 million,, $363 $224 million, $220$326 million and $118$273 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trustNDT funds.
Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2017.2018. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2017,2018, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 15 — Asset Retirement Obligations for further discussionadditional information on the NDT fund investments.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair valuehierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps 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 calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 12 — Derivative Financial Instruments for further discussionadditional information on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)
Nuclear Decommissioning TrustNDT Fund Investments and Pledged Assets for Zion Station Decommissioning (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 discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied 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. Therefore, 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.has not disclosed such inputs.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). For life insurance policies categorized as Level 3, the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon gains an understanding of the types of inputshas not disclosed such inputs.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of the valuations.
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 nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 $2.99$3.18 and $0.42$0.64 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 12 — Derivative Financial Instruments for moreadditional 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 following tables present the significant inputs to the forward curve used to value these positions:
| | Type of trade | | Fair Value at December 31, 2017 | | Valuation Technique | | Unobservable Input | | Range | | Fair Value at December 31, 2018 | | Valuation Technique | | Unobservable Input | | Range |
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 445 |
| | Discounted Cash Flow | | Forward power price | | $3 | - | $124 | | $ | 443 |
| | Discounted Cash Flow | | Forward power price | | $12 | - | $174 |
| | | | Forward gas price | | $1.27 | - | $12.80 | | | | Forward gas price | | $0.78 | - | $12.38 |
| | | | Option Model | | Volatility percentage | | 11% | - | 139% | | | | Option Model | | Volatility percentage | | 10% | - | 277% |
| | | | | | |
Mark-to-market derivatives—Proprietary trading (Exelon and Generation)(a)(b) | | $ | 26 |
| | Discounted Cash Flow | | Forward power price | | $14 | - | $94 | | $ | 56 |
| | Discounted Cash Flow | | Forward power price | | $14 | - | $174 |
| | | |
| | | | |
| |
Mark-to-market derivatives (Exelon and ComEd) | | $ | (256 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 9x | - | 10x | | $ | (249 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 10x | - | 11x |
| | | | Marketability reserve | | 4% | - | 8% | | | | Marketability reserve | | 4% | - | 8% |
| | | | Renewable factor | | 88% | - | 120% | | | | Renewable factor | | 86% | - | 120% |
______
| |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
| |
(b) | The fair values do not include cash collateral posted on level three positions of $81$76 million as of December 31, 2017.2018. |
| |
(c) | Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | Type of trade | | Fair Value at December 31, 2016 | | Valuation Technique | | Unobservable Input | | Range | | Fair Value at December 31, 2017 | | Valuation Technique | | Unobservable Input | | Range |
Mark-to-market derivatives—Economic hedges (Exelon and Generation)(a)(b) | | $ | 435 |
| | Discounted Cash Flow | | Forward power price | | $11 | - | $130 | | $ | 445 |
| | Discounted Cash Flow | | Forward power price | | $3 | - | $124 |
| | | | Forward gas price | | $1.72 | - | $9.20 | | | | Forward gas price | | $1.27 | - | $12.80 |
| | | | Option Model | | Volatility percentage | | 8% | - | 173% | | | | Option Model | | Volatility percentage | | 11% | - | 139% |
| | | | | | |
Mark-to-market derivatives— Proprietary trading (Exelon and Generation)(a)(b) | | $ | (3 | ) | | Discounted Cash Flow | | Forward power price | | $19 | - | $79 | | $ | 26 |
| | Discounted Cash Flow | | Forward power price | | $14 | - | $94 |
| | | | | | |
Mark-to-market derivatives (Exelon and ComEd) | | $ | (258 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 8x | - | 9x | | $ | (256 | ) | | Discounted Cash Flow | | Forward heat rate(c) | | 9x | - | 10x |
| | | | Marketability reserve | | 3% | - | 8% | | | | Marketability reserve | | 4% | - | 8% |
| | | | Renewable factor | | 89% | - | 121% | | | | Renewable factor | | 88% | - | 120% |
__________
| |
(a) | The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions. |
| |
(b) | The fair values do not include cash collateral posted on level three positions of $61$81 million as of December 31, 2016 2017. |
| |
(c) | Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery. |
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
12. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.
Commodity Price Risk (All Registrants)
To the extent the total amount of powerenergy Generation produces and purchases differs from the amount of powerenergy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchases andpurchase normal salessale (NPNS), cash flow hedges and fair value hedges. For Generation, all derivative
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the following tables. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.
Fair value authoritative guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy relatedenergy-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 December 31, 2017 and 2016, $4 million and $82018, $2 million of cash collateral posted with external counterparties and an additional $12 million of cash collateral posted with ComEd, and as of December 31, 2017, $4 million of cash collateral held, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by BGEPECO and PECOBGE must be deposited in a non-affiliatean unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting column.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:2018:
| | | | | | | | | | | | | | | | | | | Successor | | | | | | | | | | | | | | | |
| Generation | | ComEd | | DPL | | PHI | | Exelon | Generation | | ComEd | | Exelon |
Description | 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 | Economic Hedges | | Proprietary Trading | | Collateral and Netting(a)(d) | | Subtotal(b) | | Economic Hedges(c) | | Total Derivatives |
Mark-to-market derivative assets (current assets) | $ | 3,061 |
| | $ | 56 |
| | $ | (2,144 | ) | | $ | 973 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 973 |
| $ | 3,505 |
| | $ | 105 |
| | $ | (2,809 | ) | | $ | 801 |
| | $ | — |
| | $ | 801 |
|
Mark-to-market derivative assets (noncurrent assets) | 1,164 |
| | 12 |
| | (845 | ) | | 331 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 331 |
| 1,266 |
| | 41 |
| | (862 | ) | | 445 |
| | — |
| | 445 |
|
Total mark-to-market derivative assets | 4,225 |
|
| 68 |
|
| (2,989 | ) | | 1,304 |
| | — |
|
| — |
|
| — |
| | — |
|
| — |
| | 1,304 |
| 4,771 |
|
| 146 |
|
| (3,671 | ) | | 1,246 |
| | — |
|
| 1,246 |
|
Mark-to-market derivative liabilities (current liabilities) | (2,646 | ) | | (43 | ) | | 2,480 |
| | (209 | ) | | (21 | ) | | (1 | ) | | 1 |
| | — |
| | — |
| | (230 | ) | (3,429 | ) | | (74 | ) | | 3,056 |
| | (447 | ) | | (26 | ) | | (473 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,137 | ) | | (10 | ) | | 975 |
| | (172 | ) | | (235 | ) | | — |
| �� | — |
| | — |
| | — |
| | (407 | ) | (1,203 | ) | | (20 | ) | | 972 |
| | (251 | ) | | (223 | ) | | (474 | ) |
Total mark-to-market derivative liabilities | (3,783 | ) |
| (53 | ) |
| 3,455 |
| | (381 | ) | | (256 | ) |
| (1 | ) |
| 1 |
|
| — |
|
| — |
| | (637 | ) | (4,632 | ) |
| (94 | ) |
| 4,028 |
| | (698 | ) | | (249 | ) |
| (947 | ) |
Total mark-to-market derivative net assets (liabilities) | $ | 442 |
|
| $ | 15 |
|
| $ | 466 |
| | $ | 923 |
| | $ | (256 | ) |
| $ | (1 | ) |
| $ | 1 |
|
| $ | — |
|
| $ | — |
| | $ | 667 |
| $ | 139 |
|
| $ | 52 |
|
| $ | 357 |
| | $ | 548 |
| | $ | (249 | ) |
| $ | 299 |
|
__________
| |
(a) | Exelon Generation, PHI and DPLGeneration net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above. |
| |
(b) | Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018. |
| |
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| |
(d) | Of the collateral posted/(received), $(94) million represents variation margin on the exchanges. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Generation | | ComEd | | Exelon |
Description | Economic Hedges | | Proprietary Trading | | Collateral and Netting(a)(d) | | Subtotal(b) | | Economic Hedges(c) | | Total Derivatives |
Mark-to-market derivative assets (current assets) | $ | 3,061 |
| | $ | 56 |
| | $ | (2,144 | ) | | $ | 973 |
| | $ | — |
| | $ | 973 |
|
Mark-to-market derivative assets (noncurrent assets) | 1,164 |
| | 12 |
| | (845 | ) | | 331 |
| | — |
| | 331 |
|
Total mark-to-market derivative assets | 4,225 |
|
| 68 |
|
| (2,989 | ) | | 1,304 |
| | — |
|
| 1,304 |
|
Mark-to-market derivative liabilities (current liabilities) | (2,646 | ) | | (43 | ) | | 2,480 |
| | (209 | ) | | (21 | ) | | (230 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,137 | ) | | (10 | ) | | 975 |
| | (172 | ) | | (235 | ) | | (407 | ) |
Total mark-to-market derivative liabilities | (3,783 | ) |
| (53 | ) |
| 3,455 |
| | (381 | ) | | (256 | ) |
| (637 | ) |
Total mark-to-market derivative net assets (liabilities) | $ | 442 |
|
| $ | 15 |
|
| $ | 466 |
| | $ | 923 |
| | $ | (256 | ) |
| $ | 667 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above. |
| |
(b) | Current and noncurrent assets are shown net of collateral of $169 million and $53 million, respectively, and current and noncurrent liabilities are shown net of collateral of $167 million and $77 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $466 million at December 31, 2017. |
| |
(c) | Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers. |
| |
(d) | 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), $(117) million represents variation margin on the exchanges. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | |
| Generation | | ComEd | | DPL | | PHI | | Exelon |
Description | 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) | $ | 3,623 |
| | $ | 55 |
| | $ | (2,769 | ) | | $ | 909 |
| | $ | — |
| | $ | 2 |
| | $ | (2 | ) | | $ | — |
| | $ | — |
| | $ | 909 |
|
Mark-to-market derivative assets (noncurrent assets) | 1,467 |
| | 21 |
| | (1,016 | ) | | 472 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 472 |
|
Total mark-to-market derivative assets | 5,090 |
|
| 76 |
|
| (3,785 | ) | | 1,381 |
| | — |
| | 2 |
|
| (2 | ) |
| — |
|
| — |
|
| 1,381 |
|
Mark-to-market derivative liabilities (current liabilities) | (3,165 | ) | | (54 | ) | | 2,964 |
| | (255 | ) | | (19 | ) | | — |
| | — |
| | — |
| | — |
| | (274 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | (1,274 | ) | | (25 | ) | | 1,150 |
| | (149 | ) | | (239 | ) | | — |
| | — |
| | — |
| | — |
| | (388 | ) |
Total mark-to-market derivative liabilities | (4,439 | ) |
| (79 | ) |
| 4,114 |
| | (404 | ) | | (258 | ) | | — |
| | — |
|
| — |
|
| — |
|
| (662 | ) |
Total mark-to-market derivative net assets (liabilities) | $ | 651 |
|
| $ | (3 | ) |
| $ | 329 |
| | $ | 977 |
| | $ | (258 | ) | | $ | 2 |
| | $ | (2 | ) |
| $ | — |
|
| $ | — |
|
| $ | 719 |
|
__________
| |
(a) | Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit and other forms of non-cash collateral. These are not reflected in the table above. |
| |
(b) | Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016. |
| |
(c) | Includes current and noncurrent liabilities relating to floating-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), $(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)
Economic Hedges (Commodity Price Risk)
Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis. For the years ended December 31, 2018, 2017 2016 and 2015,2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" onin the Consolidated Statements of Cash Flows.
| | | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
Income Statement Location | | Gain (Loss) | | Gain (Loss) |
Operating revenues | | $ | (126 | ) | | $ | (490 | ) | | $ | 196 |
| | $ | (270 | ) | | $ | (126 | ) | | $ | (490 | ) |
Purchased power and fuel | | (43 | ) | | 459 |
| | 54 |
| | (47 | ) | | (43 | ) | | 459 |
|
Total Exelon and Generation | | $ | (169 | ) | | $ | (31 | ) | | $ | 250 |
| | $ | (317 | ) | | $ | (169 | ) | | $ | (31 | ) |
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions whichthat have not been hedged. Generation hedges commodity
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
price risk on a ratable basis over three-year periods. As of December 31, 2017,2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 85%-88%89%-92%, 55%-58%56%-59% and 26%-29%32%-35% for 2018, 2019, 2020 and 2020,2021, respectively.
On December 17, 2010, ComEd entered intoexecuted several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 34 — Regulatory Matters 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 3 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s commodity 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 to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 20162018 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 20162018 and previous PGC settlement,settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural gas costs are fully recovered from customers under the PGC.
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts are not derivatives.
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin (RARM). The RARM includes a fixed annual margin of approximately $2.75 million, plus an incremental cost component and a cash working capital allowance. In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement is limited. Certain of DPL’s full requirements contracts, which are considered
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecast on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas. The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month, including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions. From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full requirements contracts are not derivatives.
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for its BGS requirements through full requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered intoexecuted with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the proprietary trading activities. The proprietary trading activities are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's overall revenue from energy marketing activities. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the years ended December 31, 2018, 2017 2016 and 2015,2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" onin the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.
|
| | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2018 | | 2017 | | 2016 |
Income Statement Location | | Gain |
Operating revenues | | $ | 17 |
| | $ | 6 |
| | $ | 2 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 |
Income Statement Location | | Gain (Loss) |
Operating revenues | | $ | 6 |
| | $ | 2 |
| | $ | (6 | ) |
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants also utilize fixed-to-floating interest rate swaps, which are typically designatedtreated as fair valueeconomic hedges, to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels, which are typically designated as cash flow hedges to manage interest rate risk. To manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2017:2018:
| | | Generation | | Exelon Corporate | | Exelon | Generation | | Exelon Corporate | | Exelon |
Description | Derivatives Designated as Hedging Instruments | | Economic Hedges | | Proprietary Trading | | Collateral and Netting(a) | | Subtotal | | Derivatives Designated as Hedging Instruments | | Total | | Economic Hedges | | Collateral and Netting(a) | | Subtotal | | Economic Hedges | | Total |
Mark-to-market derivative assets (current assets) | $ | — |
|
| $ | 10 |
|
| $ | — |
| | $ | (7 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| $ | 5 |
|
| $ | (2 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
Mark-to-market derivative assets (noncurrent assets) | 3 |
|
| — |
|
| — |
| | — |
| | 3 |
| | 3 |
| | 6 |
|
| 8 |
|
| (1 | ) | | 7 |
| | — |
| | 7 |
|
Total mark-to-market derivative assets | 3 |
|
| 10 |
|
| — |
| | (7 | ) | | 6 |
| | 3 |
| | 9 |
|
| 13 |
|
| (3 | ) | | 10 |
| | — |
| | 10 |
|
Mark-to-market derivative liabilities (current liabilities) | (2 | ) |
| (7 | ) |
| — |
| | 7 |
| | (2 | ) | | — |
| | (2 | ) |
| (4 | ) |
| 2 |
| | (2 | ) | | — |
| | (2 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | — |
|
| (2 | ) |
| — |
| | — |
| | (2 | ) | | — |
| | (2 | ) |
| (2 | ) |
| 1 |
| | (1 | ) | | (4 | ) | | (5 | ) |
Total mark-to-market derivative liabilities | (2 | ) |
| (9 | ) |
| — |
| | 7 |
| | (4 | ) | | — |
| | (4 | ) |
| (6 | ) |
| 3 |
| | (3 | ) | | (4 | ) | | (7 | ) |
Total mark-to-market derivative net assets (liabilities) | $ | 1 |
|
| $ | 1 |
|
| $ | — |
| | $ | — |
| | $ | 2 |
| | $ | 3 |
| | $ | 5 |
|
| $ | 7 |
|
| $ | — |
| | $ | 7 |
| | $ | (4 | ) | | $ | 3 |
|
__________
| |
(a) | Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2016:2017:
| | | 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 | | Collateral and Netting(a) | | Subtotal | | Derivatives Designated as Hedging Instruments | | Total |
Mark-to-market derivative assets (current assets) | $ | — |
|
| $ | 17 |
|
| $ | 4 |
|
| $ | (13 | ) | | $ | 8 |
| | $ | — |
| | $ | 8 |
| $ | — |
| | $ | 10 |
| | $ | (7 | ) | | $ | 3 |
| | $ | — |
| | $ | 3 |
|
Mark-to-market derivative assets (noncurrent assets) | — |
|
| 11 |
|
| 1 |
|
| (8 | ) | | 4 |
| | 16 |
| | 20 |
| 3 |
| | — |
| | — |
| | 3 |
| | 3 |
| | 6 |
|
Total mark-to-market derivative assets | — |
|
| 28 |
|
| 5 |
|
| (21 | ) | | 12 |
| | 16 |
|
| 28 |
| 3 |
|
| 10 |
|
| (7 | ) | | 6 |
| | 3 |
| | 9 |
|
Mark-to-market derivative liabilities (current liabilities) | (7 | ) |
| (13 | ) |
| (2 | ) |
| 14 |
| | (8 | ) | | — |
| | (8 | ) | (2 | ) | | (7 | ) | | 7 |
| | (2 | ) | | — |
| | (2 | ) |
Mark-to-market derivative liabilities (noncurrent liabilities) | (3 | ) |
| (8 | ) |
| (2 | ) |
| 9 |
| | (4 | ) | | — |
| | (4 | ) | — |
| | (2 | ) | | — |
| | (2 | ) | | — |
| | (2 | ) |
Total mark-to-market derivative liabilities | (10 | ) |
| (21 | ) |
| (4 | ) |
| 23 |
| | (12 | ) | | — |
|
| (12 | ) | (2 | ) |
| (9 | ) |
| 7 |
| | (4 | ) | | — |
| | (4 | ) |
Total mark-to-market derivative net assets (liabilities) | $ | (10 | ) |
| $ | 7 |
|
| $ | 1 |
|
| $ | 2 |
| | $ | — |
| | $ | 16 |
|
| $ | 16 |
| $ | 1 |
|
| $ | 1 |
|
| $ | — |
| | $ | 2 |
| | $ | 3 |
| | $ | 5 |
|
__________
| |
(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 authoritative guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases, Exelon and Generation may have other offsetting counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral, which are not reflected in the table above. |
Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation execute these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at fair value through earnings going forward, referred to as economic hedges in the following tables.
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2018 related to interest rate swaps and foreign currency exchange rate swaps.
|
| | | | | | | | | | | | |
| | Generation | | Exelon Corporate | | Exelon |
Foreign currency exchange rate swaps | | $ | 268 |
| | $ | — |
| | $ | 268 |
|
Interest rate swaps | | 620 |
| | 800 |
| | 1,420 |
|
Total | | $ | 888 |
| | $ | 800 |
| | $ | 1,688 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign currency exchange rate swaps.
|
| | | | | | | | | | | | |
| | Generation | | Exelon Corporate | | Exelon |
Foreign currency exchange rate swaps | | $ | 94 |
| | $ | — |
| | $ | 94 |
|
Interest rate swaps(a) | | 1 |
| | — |
| | 1 |
|
Total | | $ | 95 |
| | $ | — |
| | $ | 95 |
|
__________
| |
(a) | On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017. |
For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
|
| | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2018 | | 2017 | | 2016 |
| | Income Statement Location | | Gain (Loss) |
Generation | | Operating Revenues | | $ | 7 |
| | $ | (6 | ) | | $ | (10 | ) |
Generation | | Purchased Power and Fuel | | (9 | ) | | — |
| | — |
|
Generation | | Interest Expense | | (7 | ) | | (3 | ) | | — |
|
Total Generation | | | | $ | (9 | ) | | $ | (9 | ) | | $ | (10 | ) |
|
| | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2018 | | 2017 | | 2016 |
| | Income Statement Location | | Gain (Loss) |
Exelon | | Operating Revenues | | $ | 7 |
| | $ | (6 | ) | | $ | (10 | ) |
Exelon | | Purchased Power and Fuel | | (9 | ) | | — |
| | — |
|
Exelon | | Interest Expense | | (4 | ) | | (3 | ) | | — |
|
Total Exelon | | | | $ | (6 | ) | | $ | (9 | ) | | $ | (10 | ) |
Fair Value Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon had no fixed-to-floating swaps designated as fair value hedges as of December 31, 2018 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017. Exelon and Generation include the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| Income Statement Location | | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 |
| Gain (Loss) on Swaps | | Gain (Loss) on Borrowings |
Generation | Interest expense(a) | | $ | — |
| | $ | — |
| | $ | (1 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
Exelon | Interest expense | | (13 | ) | | (9 | ) | | 3 |
| | 28 |
| | 23 |
| | 14 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, |
| Income Statement Location | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 |
| Loss on Swaps | | Gain on Borrowings |
Exelon | Interest expense | | $ | (11 | ) | | $ | (13 | ) | | $ | (9 | ) | | $ | 20 |
| | $ | 28 |
| | $ | 23 |
|
__________During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations due to ineffectiveness from fair value hedges were gains of $9 million, $15 million and $14 million, respectively.
| |
(a) | For the year ended December 31, 2015, the loss on Generation swaps included $(1) million realized in earnings with an immaterial amount excluded from hedge effectiveness testing. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The table below provides the notional amounts of fixed-to-floating hedges outstanding held by Exelon at December 31, 2017 and 2016.
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 |
Fixed-to-floating hedges | | $ | 800 |
| | $ | 800 |
|
During the years ended December 31, 2017, 2016 and 2015, the impact on the results of operations due to ineffectiveness from fair value hedges were gains of $15 million, $14 million and $17 million, respectively.
Cash Flow Hedges (Interest Rate Risk)
For derivative instruments that qualify and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI and reclassified into earnings when the underlying transaction occurs. To mitigate interest rate risk, Exelon and Generation enter intohave no floating-to-fixed interest rate swaps to manage a portiondesignated as cash flow hedges as of interest rate exposure associated with debt issuances. The table below provides theDecember 31, 2018, and had $636 million notional amounts of floating-to-fixeddesignated as cash flow hedges outstanding held by Exelon and Generation atas of December 31, 2017 and 2016.
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 |
Floating-to-fixed hedges | | $ | 636 |
| | $ | 659 |
|
2017.The tables below provide the activity of OCI related to cash flow hedges for the years ended December 31, 20172018 and 2016,2017, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
|
| | | | | | | | | | | |
| | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | |
| | | | Generation | | Exelon | |
For the Year Ended December 31, 2017 | | Income Statement Location | | Total Cash Flow Hedges | | Total Cash Flow Hedges | |
AOCI derivative loss at December 31, 2016 | | | | $ | (19 | ) | | $ | (17 | ) | |
Effective portion of changes in fair value | | | | (1 | ) | | (1 | ) | |
Reclassifications from AOCI to net income | | Interest expense | | 4 |
| (a) | 4 |
| (a) |
AOCI derivative loss at December 31, 2017 | | | | $ | (16 | ) | | $ | (14 | ) | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | |
| | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | |
| | | | Generation | | Exelon | |
For the Year Ended December 31, 2018 | | Income Statement Location | | Total Cash Flow Hedges | | Total Cash Flow Hedges | |
AOCI derivative loss at December 31, 2017 | | | | $ | (16 | ) | | $ | (14 | ) | |
Effective portion of changes in fair value | | | | 11 |
| | 11 |
| |
Reclassifications from AOCI to net income | | Interest expense | | 1 |
| | 1 |
| |
AOCI derivative loss at December 31, 2018 | | | | $ | (4 | ) | | $ | (2 | ) | |
| | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | | | Total Cash Flow Hedge AOCI Activity, Net of Income Tax | |
| | Generation | | Exelon | | | Generation | | Exelon | |
For the Year Ended December 31, 2016 | | Income Statement Location | | Total Cash Flow Hedges | | Total Cash Flow Hedges | | |
AOCI derivative loss at December 31, 2015 | | $ | (21 | ) | | $ | (19 | ) | | |
For the Year Ended December 31, 2017 | | | Income Statement Location | | Total Cash Flow Hedges | | Total Cash Flow Hedges | |
AOCI derivative loss at December 31, 2016 | | | $ | (19 | ) | | $ | (17 | ) | |
Effective portion of changes in fair value | | (6 | ) | | (6 | ) | | | (1 | ) | | (1 | ) | |
Reclassifications from AOCI to net income | | Interest expense | | 8 |
| (b) | 8 |
| (b) | | Interest expense | | 4 |
| (a) | 4 |
| (a) |
AOCI derivative loss at December 31, 2016 | | $ | (19 | ) | | $ | (17 | ) | | |
AOCI derivative loss at December 31, 2017 | | | $ | (16 | ) | | $ | (14 | ) | |
__________
| |
(a) | Amount is net of related income tax expense of $1 million for the year ended December 31, 2017. |
| |
(b) | Amount is net of related income tax expense of $5 million for the year ended December 31, 2016. |
During the years ended December 31, 2018, 2017 2016 and 2015,2016, the impact on the results of operations due to theas a result of ineffectiveness from cash flow hedges that continue to be designated in hedging relationships was immaterial. The estimated amount of existing gains and losses that are reported in AOCI at the reporting date that are expected to be reclassified into earnings within the next twelve months is immaterial.
Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation executes these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash flow hedge elections were not made. Generation also 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.
At December 31, 2017 and 2016, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 and 2016 related to foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.
|
| | | | | | | | |
| | For the Years Ended December 31, |
| | 2017 | | 2016 |
Foreign currency exchange rate swaps | | $ | 94 |
| | $ | 85 |
|
For the years ended December 31, 2017, 2016 and 2015, Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
|
| | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2017 | | 2016 | | 2015 |
| | Income Statement Location | | Gain (Loss) |
Generation | | Operating Revenues | | $ | (6 | ) | | $ | (10 | ) | | $ | 7 |
|
Generation | | Interest Expense | | (3 | ) | | — |
| | — |
|
Total Generation | | | | $ | (9 | ) | | $ | (10 | ) | | $ | 7 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | |
| | | | For the Years Ended December 31, |
| | | | 2017 | | 2016 | | 2015 |
| | Income Statement Location | | Gain (Loss) |
Exelon | | Operating Revenues | | $ | (6 | ) | | $ | (10 | ) | | $ | 7 |
|
Exelon | | Interest Expense | | (3 | ) | | — |
| | 100 |
|
Total Exelon | | | | $ | (9 | ) | | $ | (10 | ) | | $ | 107 |
|
Proprietary Trading (Interest Rate and Foreign Exchange Risk)
Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. For the years ended December 31, 2018, 2017 2016 and 2015,2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).
| | | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 |
Income Statement Location | | Gain (Loss) | | Loss |
Operating revenues | | $ | (1 | ) | | $ | (1 | ) | | $ | (2 | ) | | $ | — |
| | $ | (1 | ) | | $ | (1 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Credit Risk, Collateral and Contingent-Related Features (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2017.2018. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX and Nodal commodity exchanges. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $28$43 million, $22$30 million, $24 million, $36$28 million, $12$7 million and $6$5 million as of December 31, 2017,2018, respectively.
| | Rating as of December 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 | |
Rating as of December 31, 2018 | | Total Exposure Before Credit Collateral | | Credit Collateral (a) | | Net Exposure | | Number of Counterparties Greater than 10% of Net Exposure | | Net Exposure of Counterparties Greater than 10% of Net Exposure |
Investment grade | $ | 738 |
|
| $ | 4 |
| | $ | 734 |
| | 1 |
| | $ | 244 |
| $ | 795 |
|
| $ | — |
| | $ | 795 |
| | 1 |
| | $ | 153 |
|
Non-investment grade | 90 |
|
| 12 |
| | 78 |
| | — |
| | — |
| 133 |
|
| 45 |
| | 88 |
| | — |
| | — |
|
No external ratings |
|
|
| |
| | | | |
|
|
| |
| | | | |
Internally rated — investment grade | 253 |
|
| — |
| | 253 |
| | — |
| | — |
| 181 |
|
| 1 |
| | 180 |
| | — |
| | — |
|
Internally rated — non-investment grade | 83 |
|
| 11 |
| | 72 |
| | — |
| | — |
| 92 |
|
| 6 |
| | 86 |
| | — |
| | — |
|
Total | $ | 1,164 |
|
| $ | 27 |
| | $ | 1,137 |
| | 1 |
| | $ | 244 |
| $ | 1,201 |
|
| $ | 52 |
| | $ | 1,149 |
| | 1 |
| | $ | 153 |
|
| | Net Credit Exposure by Type of Counterparty | December 31, 2017 | December 31, 2018 |
Financial institutions | $ | 41 |
| $ | 12 |
|
Investor-owned utilities, marketers, power producers | 558 |
| 737 |
|
Energy cooperatives and municipalities | 452 |
| 324 |
|
Other | 86 |
| 76 |
|
Total | $ | 1,137 |
| $ | 1,149 |
|
__________
| |
(a) | As of December 31, 2017,2018, credit collateral held from counterparties where Generation had credit exposure included $8$17 million of cash and $19$35 million of letters of credit. The credit collateral does not include non-liquid collateral. |
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2017,2018, ComEd’s net credit exposure to suppliers was approximately $1 million.immaterial.
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 34 — Regulatory Matters for additional information.
PECO’s unsecured credit used by theelectric suppliers represents PECO’s net credit exposure. As of December 31, 2017,2018, PECO had no material net credit exposure to electric suppliers.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 December 31, 2017,2018, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 34 — Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of December 31, 2017,2018, BGE had no material net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. At December 31, 2017,2018, BGE had credit exposure of $4$3 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.
Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of December 31, 2017,2018, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 34 — Regulatory Matters for additional information.
DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of December 31, 2017,2018, DPL's credit exposure under its natural gas supply and asset management agreements was immaterial.
Collateral (All Registrants)
As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation also enters into commodity transactions on exchanges. Theexchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-relatedcredit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk-relatedcredit-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:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
Credit-Risk Related Contingent Feature | 2017 | | 2016 | 2018 | | 2017 |
Gross fair value of derivative contracts containing this feature(a) | $ | (926 | ) | | $ | (960 | ) | $ | (1,723 | ) | | $ | (926 | ) |
Offsetting fair value of in-the-money contracts under master netting arrangements(b) | 577 |
| | 627 |
| 1,105 |
| | 577 |
|
Net fair value of derivative contracts containing this feature(c) | $ | (349 | ) | | $ | (333 | ) | $ | (618 | ) | | $ | (349 | ) |
__________
| |
(a) | Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements. |
| |
(b) | Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral. |
| |
(c) | Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based. |
Generation had cash collateral posted of $418 million and letters of credit posted of $367 million, and cash collateral held of $47 million and letters of credit held of $44 million as of December 31, 2018 for external counterparties with derivative positions. Generation had cash collateral posted of $497 million and letters of credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33 million as ofat December 31, 2017 for external counterparties with derivative positions. Generation had cash collateral posted of $347 million and letters of credit posted of $284 million and cash collateral held of $24 million and letters of credit held of $28 million at December 31, 2016 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $1.8$2.1 billion and $1.9$1.8 billion as of December 31, 20172018 and 2016,2017, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2017,2018, Generation’s and Exelon's swaps were in an asset position with a fair value of $2$7 million and $5$3 million, respectively.
See Note 2524 — Segment Information for furtheradditional information regarding the letters of credit supporting the cash collateral.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2017,2018, ComEd held approximately $10$38 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd’s renewable energy certificate (REC)ComEd's ZEC contracts, collateral postings are required to cover a percentage of the ZEC contract value. ComEd’s REC contracts require collateral postings that are either a fixed price per REC or a percentage of the REC contract value. As of December 31, 2017,2018, ComEd held approximately $2$31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2017,2018, ComEd held approximately $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of December 31, 2017,2018, it would have been required to post approximately $14$7 million of collateral to its counterparties. See Note 34 — Regulatory Matters 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 December 31, 2017,2018, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2017,2018, PECO could have been required to post approximately $34$39 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 natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2017,2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2017,2018, BGE could have been required to post approximately $66$69 million of collateral to its counterparties.
DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of December 31, 2017,2018, DPL could have been required to post an additional amount of approximately $11 million of collateral to its natural gas counterparties.
BGE's, Pepco's, DPL's and ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
13. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, BGE, Pepco, DPL and BGEACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. 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.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 20172018 and 2016:2017:
| | | Maximum Program Size at December 31, | | Outstanding Commercial Paper at December 31, | | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, | Maximum Program Size at December 31, | | Outstanding Commercial Paper at December 31, | | Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31, |
Commercial Paper Issuer | 2017(a)(b)(c) | | 2016(a)(b)(c) | | 2017 | | 2016 | | 2017 | | 2016 | 2018(a)(b)(c) | | 2017(a)(b)(c) | | 2018 | | 2017 | | 2018 | | 2017 |
Exelon Corporate | $ | 600 |
| | $ | 600 |
| | $ | — |
| | $ | — |
| | 1.16 | % | | 0.70 | % | $ | 600 |
| | $ | 600 |
| | $ | — |
| | $ | — |
| | 1.93 | % | | 1.16 | % |
Generation | 5,300 |
| | 5,300 |
| | — |
| | 620 |
| | 1.23 | % | | 0.94 | % | 5,300 |
| | 5,300 |
| | — |
| | — |
| | 1.96 | % | | 1.23 | % |
ComEd | 1,000 |
| | 1,000 |
| | — |
| | — |
| | 1.24 | % | | 0.77 | % | 1,000 |
| | 1,000 |
| | — |
| | — |
| | 2.14 | % | | 1.24 | % |
PECO | 600 |
| | 600 |
| | — |
| | — |
| | 1.13 | % | | N/A |
| 600 |
| | 600 |
| | — |
| | — |
| | 2.24 | % | | 1.13 | % |
BGE | 600 |
| | 600 |
| | 77 |
| | 45 |
| | 1.28 | % | | 0.77 | % | 600 |
| | 600 |
| | 35 |
| | 77 |
| | 2.18 | % | | 1.28 | % |
Pepco | 500 |
| | 500 |
| | 26 |
| | 23 |
| | 1.06 | % | | 0.71 | % | 300 |
| | 500 |
| | 40 |
| | 26 |
| | 2.24 | % | | 1.06 | % |
DPL | 500 |
| | 500 |
| | 216 |
| | — |
| | 1.48 | % | | 0.68 | % | 300 |
| | 500 |
| | — |
| | 216 |
| | 2.07 | % | | 1.48 | % |
ACE | 350 |
| | 350 |
| | 108 |
| | — |
| | 1.43 | % | | 0.65 | % | 300 |
| | 350 |
| | 14 |
| | 108 |
| | 2.21 | % | | 1.43 | % |
Total | $ | 9,450 |
|
| $ | 9,450 |
|
| $ | 427 |
|
| $ | 688 |
| | | | | $ | 9,000 |
|
| $ | 9,450 |
|
| $ | 89 |
|
| $ | 427 |
| | | | |
__________
| |
(a) | Excludes $480$545 million and $500$480 million in bilateral credit facilities thatat December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program at December 31, 2017 and 2016, respectively.program. |
| |
(b) | Excludes additionalAt December 31, 2018, excludes $135 million of credit facility agreements forarranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million, and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 12, 2018. These facilities are solely utilized to issue letters of credit. As of December 31, 2017, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively. |
| |
(c) | Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility. |
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of outstanding commercial paper does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2017,2018, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:
| | | | | | | | | | Available Capacity at December 31, 2017 | | | | | | | | Available Capacity at December 31, 2018 |
Borrower | Facility Type | | Aggregate Bank Commitment(a)(b) | | Facility Draws | | Outstanding Letters of Credit(c) | | Actual | | To Support Additional Commercial Paper(b)(d) | Facility Type | | Aggregate Bank Commitment(a) | | Facility Draws | | Outstanding Letters of Credit | | Actual | | To Support Additional Commercial Paper(b) |
Exelon Corporate | Syndicated Revolver | | $ | 600 |
| | $ | — |
| | $ | 45 |
| | $ | 555 |
| | $ | 555 |
| Syndicated Revolver | | $ | 600 |
| | $ | — |
| | $ | 9 |
| | $ | 591 |
| | $ | 591 |
|
Generation | | Syndicated Revolver | | 5,300 |
| | — |
| | 1,203 |
| | 4,097 |
| | 4,097 |
|
Generation | Syndicated Revolver | | 5,300 |
| | — |
| | 868 |
| | 4,432 |
| | 4,432 |
| Bilaterals | | 545 |
| | — |
| | 353 |
| | 192 |
| | — |
|
Generation | Bilaterals | | 480 |
| | — |
| | 231 |
| | 249 |
| | — |
| Project Finance | | 159 |
| | — |
| | 119 |
| | 40 |
| | — |
|
ComEd | Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 998 |
| Syndicated Revolver | | 1,000 |
| | — |
| | 2 |
| | 998 |
| | 998 |
|
PECO | Syndicated Revolver | | 600 |
| | — |
| | 1 |
| | 599 |
| | 599 |
| Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 600 |
|
BGE | Syndicated Revolver | | 600 |
| | — |
| | — |
| | 600 |
| | 523 |
| Syndicated Revolver | | 600 |
| | — |
| | 1 |
| | 599 |
| | 564 |
|
Pepco | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 274 |
| Syndicated Revolver | | 300 |
| | — |
| | 8 |
| | 292 |
| | 252 |
|
DPL | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 84 |
| Syndicated Revolver | | 300 |
| | — |
| | 1 |
| | 299 |
| | 299 |
|
ACE | Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 192 |
| Syndicated Revolver | | 300 |
| | — |
| | — |
| | 300 |
| | 286 |
|
Total | | $ | 9,480 |
| | $ | — |
| | $ | 1,147 |
| | $ | 8,333 |
| | $ | 7,657 |
| | $ | 9,704 |
| | $ | — |
| | $ | 1,696 |
| | $ | 8,008 |
| | $ | 7,687 |
|
__________
| |
(a) | Excludes additional$135 million of credit facility agreements forarranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34$33 million, $34 million, $5 million, $2$5 million, $2$5 million and $2$5 million, respectively, arranged with minority and community banks located primarily within utilities' service territories.respectively. These facilities expire on October 12, 2018.11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2017,2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively. |
| |
(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 discussion below on Antelope Valley Solar Ranch One and Continental Wind. |
| |
(d) | Excludes $480 million in bilateral credit facilities that do not back Generation’s commercial paper program. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2018, 2017 2016 and 2015.2016.
| | Exelon | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 823 |
| | $ | 1,125 |
| | | $ | 499 |
| $ | 531 |
| | $ | 823 |
| | | $ | 1,125 |
|
Maximum borrowings outstanding | 2,147 |
| | 3,076 |
| | 739 |
| 1,237 |
| | 2,147 |
| | 3,076 |
|
Average interest rates, computed on a daily basis | 1.32 | % | | 0.88 | % | | 0.53 | % | 2.21 | % | | 1.32 | % | | 0.88 | % |
Average interest rates, at December 31 | 1.24 | % | | 1.12 | % | | 0.88 | % | 2.15 | % | | 1.24 | % | | 1.12 | % |
| | | | | | | | | | |
Generation | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 405 |
| | $ | 536 |
| | | $ | 1 |
| $ | 37 |
| | $ | 405 |
| | | $ | 536 |
|
Maximum borrowings outstanding | 1,455 |
| | 1,735 |
| | 50 |
| 583 |
| | 1,455 |
| | 1,735 |
|
Average interest rates, computed on a daily basis | 1.23 | % | | 0.94 | % | | 0.49 | % | 1.96 | % | | 1.23 | % | | 0.94 | % |
Average interest rates, at December 31 | 1.23 | % | | 1.14 | % | | N/A |
| 1.96 | % | | 1.23 | % | | 1.14 | % |
| | ComEd | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 200 |
| | $ | 256 |
| | | $ | 461 |
| $ | 154 |
| | $ | 200 |
| | | $ | 256 |
|
Maximum borrowings outstanding | 470 |
| | 755 |
| | 684 |
| 520 |
| | 470 |
| | 755 |
|
Average interest rates, computed on a daily basis | 1.24 | % | | 0.77 | % | | 0.53 | % | 2.14 | % | | 1.24 | % | | 0.77 | % |
Average interest rates, at December 31 | 1.24 | % | | N/A |
| | 0.89 | % | 2.14 | % | | 1.24 | % | | N/A |
|
| | | | | | | | | | |
PECO | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 2 |
| | $ | — |
| | | $ | — |
| $ | 68 |
| | $ | 2 |
| | | $ | — |
|
Maximum borrowings outstanding | 60 |
| | — |
| | — |
| 350 |
| | 60 |
| | — |
|
Average interest rates, computed on a daily basis | 1.13 | % | | N/A |
| | N/A |
| 2.24 | % | | 1.13 | % | | N/A |
|
Average interest rates, at December 31 | 1.13 | % | | N/A |
| | N/A |
| 2.24 | % | | 1.13 | % | | N/A |
|
| | | | | | | | | | |
BGE | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 54 |
| | $ | 143 |
| | | $ | 37 |
| $ | 65 |
| | $ | 54 |
| | | $ | 143 |
|
Maximum borrowings outstanding | 165 |
| | 369 |
| | 210 |
| 239 |
| | 165 |
| | 369 |
|
Average interest rates, computed on a daily basis | 1.28 | % | | 0.77 | % | | 0.48 | % | 2.18 | % | | 1.28 | % | | 0.77 | % |
Average interest rates, computed at December 31 | 1.28 | % | | 0.95 | % | | 0.87 | % | 2.18 | % | | 1.28 | % | | 0.95 | % |
| | | | | | | | | | |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | PHI Corporate | | | | | | | | | | |
| Successor | | Predecessor | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | N/A |
| | $ | 153 |
| | | $ | 444 |
| N/A |
| | N/A |
| | | $ | 153 |
|
Maximum borrowings outstanding | N/A |
| | 559 |
| | | 784 |
| N/A |
| | N/A |
| | 559 |
|
Average interest rates, computed on a daily basis | N/A |
| | 1.03 | % | | | 0.90 | % | N/A |
| | N/A |
| | 1.03 | % |
Average interest rates, computed at December 31 | N/A |
| | N/A |
| | | 1.22 | % | N/A |
| | N/A |
| | N/A |
|
| | | | | | | | | | |
Pepco | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 51 |
| | $ | 4 |
| | | $ | 34 |
| $ | 22 |
| | $ | 51 |
| | | $ | 4 |
|
Maximum borrowings outstanding | 197 |
| | 73 |
| | 190 |
| 90 |
| | 197 |
| | 73 |
|
Average interest rates, computed on a daily basis | 1.06 | % | | 0.71 | % | | 0.44 | % | 2.24 | % | | 1.06 | % | | 0.71 | % |
Average interest rates, computed at December 31 | 1.06 | % | | 0.90 | % | | 0.68 | % | 2.24 | % | | 1.06 | % | | 0.90 | % |
| | | | | | | | | | |
DPL | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 40 |
| | $ | 33 |
| | | $ | 81 |
| $ | 87 |
| | $ | 40 |
| | | $ | 33 |
|
Maximum borrowings outstanding | 216 |
| | 116 |
| | 179 |
| 245 |
| | 216 |
| | 116 |
|
Average interest rates, computed on a daily basis | 1.48 | % | | 0.68 | % | | 0.47 | % | 2.07 | % | | 1.48 | % | | 0.68 | % |
Average interest rates, computed at December 31 | 1.48 | % | | N/A |
| | 0.79 | % | 2.07 | % | | 1.48 | % | | N/A |
|
| | | | | | | | | | |
ACE | | | | | | | | | | |
| 2017 | | 2016 | | | 2015 | 2018 | | 2017 | | | 2016 |
Average borrowings | $ | 30 |
| | $ | — |
| | | $ | 175 |
| $ | 95 |
| | $ | 30 |
| | | $ | — |
|
Maximum borrowings outstanding | 133 |
| | 5 |
| | 253 |
| 210 |
| | 133 |
| | 5 |
|
Average interest rates, computed on a daily basis | 1.43 | % | | 0.65 | % | | 0.46 | % | 2.21 | % | | 1.43 | % | | 0.65 | % |
Average interest rates, computed at December 31 | 1.43 | % | | N/A |
| | 0.65 | % | 2.21 | % | | 1.43 | % | | N/A |
|
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 general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon Corporate entered into a similar type term loan for $500 million which expiresexpired on March 22, 2018. The loan agreement was renewed on March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
On May 23, 2018, ACE entered into two term loan agreements in the aggregate amount of $125 million, which expire on May 22, 2019. Pursuant to the term loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is unsecured.
Credit Agreements
On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to April 2021.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.
On 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 and 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.
Credit Agreement
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 lines of credit. This facility does not back Generation's commercial paper program.
On April 1, 2016, the credit agreement for CENG's $100 million bilateral credit facility was amended to increase the overall facility size to $200 million.million, scheduled to mature in October of 2019. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation's commercial paper program.
On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26, 2017,2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2022.2023.
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. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to March 2021. This facility will solely be used by Generation to issue letters of credit.
On March 15, 2018, the credit agreement for a Generation bilateral credit facility of $30 million and extendwas amended to increase the maturityoverall facility size to January 2019.$95 million, scheduled to mature in March of 2020. This facility will solely be used by Generation to issue letters of credit.
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 | 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 | 27.5 | | 27.5 | | 7.5 | | — | | — | | 7.5 | | 7.5 | | 7.5 |
LIBOR-based borrowings | 127.5 | | 127.5 | | 107.5 | | 90.0 | | 100.0 | | 107.5 | | 107.5 | | 107.5 | 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 year ended December 31, 2017:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2018:
|
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Credit agreement threshold | 2.50 to 1 | | 3.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 | | 2.00 to 1 |
At December 31, 2017,2018, the interest coverage ratios at the Registrants were as follows:
|
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Interest coverage ratio | 6.34 | | 9.02 | | 11.68 | | 7.99 | | 10.50 | | 6.35 | | 8.69 | | 5.57 |
|
| | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
Interest coverage ratio | 7.34 | | 10.99 | | 7.34 | | 8.14 | | 9.77 | | 5.98 | | 7.03 | | 5.06 |
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default with respect to the other PHI Utilities under the PHI Utilities' combined credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under any of the borrowers' credit agreement. None of the credit agreements include any rating triggers.
Variable Rate Demand Bonds
DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2018 and December 31, 2017, and December 31, 2016, $79 million and $105 million, respectively, in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year onin Exelon's, PHI's and DPL's Consolidated Balance Sheet.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 20172018 and 2016:2017:
Exelon
|
| | | | | | | | | | | | | | | | |
| | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 |
Long-term debt | | | | | | | | | |
Rate stabilization bonds |
|
| | 5.82 | % | | 2017 | | $ | — |
| | $ | 41 |
|
First mortgage bonds(a) | 1.70 | % | - | 7.90 | % | | 2018 - 2047 | | 15,197 |
| | 14,123 |
|
Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2019 - 2046 | | 11,285 |
| | 11,868 |
|
Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2047 | | 2,600 |
| | 2,300 |
|
Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
|
Nuclear fuel procurement contracts | 3.15 | % | - | 3.35 | % | | 2018 - 2020 | | 82 |
| | 105 |
|
Notes payable and other(b)(c) | 2.61 | % | - | 8.88 | % | | 2018 - 2053 | | 405 |
| | 576 |
|
Junior subordinated notes |
| | 3.50 | % | | 2022 | | 1,150 |
| | 1,150 |
|
Contract payment - junior subordinated notes | | | 2.50 | % | | 2017 | | — |
| | 19 |
|
Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 79 |
| | 103 |
|
Unsecured Tax-Exempt Bonds | | | 5.40 | % | — |
| 2031 | | 112 |
| | 112 |
|
Medium-Terms Notes (unsecured) | 6.81 | % | - | 7.72 | % | — |
| 2018 - 2027 | | 26 |
| | 40 |
|
Transition bonds | 5.05 | % | - | 5.55 | % | — |
| 2020 - 2023 | | 90 |
| | 124 |
|
Nonrecourse debt: | | | | | | | | | |
Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,331 |
| | 1,400 |
|
Variable rates | 3.18 | % | - | 4.00 | % | | 2019 - 2024 | | 865 |
| | 915 |
|
Total long-term debt | | | | | | | 33,657 |
| | 33,311 |
|
Unamortized debt discount and premium, net | | | | | | | (57 | ) | | (68 | ) |
Unamortized debt issuance costs | | | | | | | (201 | ) | | (200 | ) |
Fair value adjustment | | | | | | | 865 |
| | 962 |
|
Long-term debt due within one year | | | | | | | (2,088 | ) | | (2,430 | ) |
Long-term debt | | | | | | | $ | 32,176 |
| | $ | 31,575 |
|
Long-term debt to financing trusts(d) | | | | | | | | | |
Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
|
Subordinated debentures to PECO Trust III | | | 7.38 | % | | 2028 | | 81 |
| | 81 |
|
Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
|
Subordinated debentures to BGE Capital Trust II | | | 6.20 | % | | 2043 | | — |
| | 258 |
|
Total long-term debt to financing trusts | | | | | | | 390 |
| | 648 |
|
Unamortized debt issuance costs | | | | | | | (1 | ) | | (7 | ) |
Long-term debt to financing trusts | | | | | | | $ | 389 |
| | $ | 641 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | |
| | | | | Maturity Date | | December 31, |
| Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.70 | % | - | 7.90 | % | | 2019 - 2048 | | 16,496 |
| | 15,197 |
|
Senior unsecured notes | 2.45 | % | - | 7.60 | % | | 2019 - 2046 | | 11,285 |
| | 11,285 |
|
Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2048 | | 2,900 |
| | 2,600 |
|
Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
|
Nuclear fuel procurement contracts | | | 3.15 | % | | 2020 | | 39 |
| | 82 |
|
Notes payable and other(b)(c) | 2.85 | % | - | 8.88 | % | | 2019 - 2053 | | 188 |
| | 405 |
|
Junior subordinated notes |
| | 3.50 | % | | 2022 | | 1,150 |
| | 1,150 |
|
Long-term software licensing agreement | | | 3.95 | % | | 2024 | | 73 |
| | 79 |
|
Unsecured Tax-Exempt Bonds | 1.74 | % | - | 5.40 | % | — |
| 2024 - 2031 | | 112 |
| | 112 |
|
Medium-Terms Notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
Transition bonds | | | 5.55 | % | | 2023 | | 59 |
| | 90 |
|
Loan Agreement | | | 2.00 | % | | 2023 | | 50 |
| | — |
|
Nonrecourse debt: | | | | | | | | | |
Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,253 |
| | 1,331 |
|
Variable rates(f) |
|
| | 5.81 | % | | 2019 - 2024 | | 849 |
| | 865 |
|
Total long-term debt | | | | | | | 34,911 |
| | 33,657 |
|
Unamortized debt discount and premium, net | | | | | | | (66 | ) | | (57 | ) |
Unamortized debt issuance costs | | | | | | | (216 | ) | | (201 | ) |
Fair value adjustment | | | | | | | 795 |
| | 865 |
|
Long-term debt due within one year(e) | | | | | | | (1,349 | ) | | (2,088 | ) |
Long-term debt | | | | | | | $ | 34,075 |
| | $ | 32,176 |
|
Long-term debt to financing trusts(d) | | | | | | | | | |
Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
|
Subordinated debentures to PECO Trust III | 7.38 | % | - | 7.50 | % | | 2028 | | 81 |
| | 81 |
|
Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
|
Total long-term debt to financing trusts | | | | | | | 390 |
| | 390 |
|
Unamortized debt issuance costs | | | | | | | — |
| | (1 | ) |
Long-term debt to financing trusts | | | | | | | $ | 390 |
| | $ | 389 |
|
__________
| |
(a) | Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures. |
| |
(b) | Includes capital lease obligations of $53$36 million and $69$53 million at December 31, 20172018 and 2016,2017, respectively. Lease payments of $18 million, $20$21 million, $5 million, $1 million,, $1 $1 million, less than $1 million, and $8 million will be made in 2018, 2019, 2020, 2021, 2022, 2023, and thereafter, respectively. |
| |
(c) | Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. As of December 31, 2016, $198 million was outstanding. |
| |
(d) | Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets. |
| |
(e) | In January 2019, $300 million of ComEd long-term debt due within one year was paid in full. |
| |
(f) | Excludes interest on CEU Upstream nonrecourse debt, see discussion below. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
Senior unsecured notes | 2.95 | % | - | 7.60 | % | | 2019 - 2042 | | $ | 6,019 |
| | $ | 5,971 |
| 2.95 | % | - | 7.60 | % | | 2019 - 2042 | | $ | 6,019 |
| | $ | 6,019 |
|
Pollution control notes | 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
| 2.50 | % | - | 2.70 | % | | 2025 - 2036 | | 435 |
| | 435 |
|
Nuclear fuel procurement contracts | 3.15 | % | - | 3.35 | % | | 2018 - 2020 | | 82 |
| | 105 |
| |
| 3.15 | % | | 2020 | | 39 |
| | 82 |
|
Notes payable and other(a)(b) | 2.61 | % | - | 8.88 | % | | 2018 - 2019 | | 223 |
| | 382 |
| 2.85 | % | - | 7.83 | % | | 2019 - 2024 | | 164 |
| | 223 |
|
Nonrecourse debt: | | | | | | | | | | | | | | |
Fixed rates | 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,331 |
| | 1,400 |
| 2.29 | % | - | 6.00 | % | | 2031 - 2037 | | 1,253 |
| | 1,331 |
|
Variable rates(c) | 3.18 | % | - | 4.00 | % | | 2019 - 2024 | | 865 |
| | 915 |
| |
| 5.81 | % | | 2019 - 2024 | | 849 |
| | 865 |
|
Total long-term debt | | | | | 8,955 |
| | 9,208 |
| | | | | 8,759 |
| | 8,955 |
|
Unamortized debt discount and premium, net | | | | | (8 | ) | | (17 | ) | | | | | (6 | ) | | (8 | ) |
Unamortized debt issuance costs | | | | | (60 | ) | | (65 | ) | | | | | (51 | ) | | (60 | ) |
Fair value adjustment | | | | | 103 |
| | 115 |
| | | | | 91 |
| | 103 |
|
Long-term debt due within one year | | | | | (346 | ) | | (1,117 | ) | | | | | (906 | ) | | (346 | ) |
Long-term debt | | | | | $ | 8,644 |
| | $ | 8,124 |
| | | | | $ | 7,887 |
| | $ | 8,644 |
|
__________
| |
(a) | Includes Generation’s capital lease obligations of $18$14 million and $22$18 million at December 31, 20172018 and 2016,2017, respectively. Generation will make lease payments of $5 million, $6$7 million, $5 million, $1 million, and $1 million in 2018, 2019, 2020, 2021, and 2022, respectively. TheLease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease matures in 2022.2024. |
| |
(b) | Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance. As of December 31, 2016, $198 million was outstanding. |
| |
(c) | Excludes interest on CEU Upstream nonrecourse debt, see discussion below. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
First mortgage bonds(a) | 2.15 | % | - | 6.45 | % | | 2018 - 2047 | | $ | 7,529 |
| | $ | 6,954 |
| 2.15 | % | - | 6.45 | % | | 2019 - 2048 | | $ | 8,179 |
| | $ | 7,529 |
|
Notes payable and other(b) | 6.95 | % | - | 7.49 | % | | 2018 - 2053 | | 147 |
| | 147 |
|
|
| | 7.49 | % | | 2053 | | 8 |
| | 147 |
|
Total long-term debt | | | | | 7,676 |
| | 7,101 |
| | | | | 8,187 |
| | 7,676 |
|
Unamortized debt discount and premium, net | | | | | (23 | ) | | (22 | ) | | | | | (23 | ) | | (23 | ) |
Unamortized debt issuance costs | | | | | (52 | ) | | (46 | ) | | | | | (63 | ) | | (52 | ) |
Long-term debt due within one year(d) | | | | | (840 | ) | | (425 | ) | | | | | (300 | ) | | (840 | ) |
Long-term debt | | | | | $ | 6,761 |
| | $ | 6,608 |
| | | | | $ | 7,801 |
| | $ | 6,761 |
|
Long-term debt to financing trust(c) | | | | | | | | | | | | | | |
Subordinated debentures to ComEd Financing III | | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
| | | 6.35 | % | | 2033 | | $ | 206 |
| | $ | 206 |
|
Total long-term debt to financing trusts | | | | | 206 |
| | 206 |
| | | | | 206 |
| | 206 |
|
Unamortized debt issuance costs | | | | | (1 | ) | | (1 | ) | | | | | (1 | ) | | (1 | ) |
Long-term debt to financing trusts | | | | | $ | 205 |
| | $ | 205 |
| | | | | $ | 205 |
| | $ | 205 |
|
__________
| |
(a) | Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture. |
| |
(b) | Includes ComEd’s capital lease obligations of $8 million at both December 31, 20172018 and 2016,2017, respectively. Lease payments of less than $1 million annually will be made from 20182019 through expiration at 2053. |
| |
(c) | Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets. |
| |
(d) | In January 2019, the $300 million balance was paid in full. |
PECO
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
First mortgage bonds(a) | 1.70 | % | - | 5.95 | % | | 2018 - 2047 | | $ | 2,925 |
| | $ | 2,600 |
| 1.70 | % | - | 5.95 | % | | 2021 - 2048 | | $ | 3,075 |
| | $ | 2,925 |
|
Loan Agreement | | | | 2.00 | % | | 2023 | | 50 |
| | 0 |
|
Total long-term debt | | | | | 2,925 |
| | 2,600 |
| | | | | 3,125 |
| | 2,925 |
|
Unamortized debt discount and premium, net | | | | | (5 | ) | | (5 | ) | | | | | (18 | ) | | (5 | ) |
Unamortized debt issuance costs | | | | | (17 | ) | | (15 | ) | | | | | (23 | ) | | (17 | ) |
Long-term debt due within one year | | | | | (500 | ) | | — |
| | | | | — |
| | (500 | ) |
Long-term debt | | | | | $ | 2,403 |
| | $ | 2,580 |
| | | | | $ | 3,084 |
| | $ | 2,403 |
|
Long-term debt to financing trusts(b) | | | | | | | | | | | | | | |
Subordinated debentures to PECO Trust III | | | 7.38 | % | | 2028 | | $ | 81 |
| | $ | 81 |
| 7.38 | % | - | 7.50 | % | | 2028 | | $ | 81 |
| | $ | 81 |
|
Subordinated debentures to PECO Trust IV | | | 5.75 | % | | 2033 | | 103 |
| | 103 |
| | | 5.75 | % | | 2033 | | 103 |
| | 103 |
|
Long-term debt to financing trusts | | | | | $ | 184 |
| | $ | 184 |
| | | | | $ | 184 |
| | $ | 184 |
|
__________
| |
(a) | Substantially all of PECO’s assets are subject to the lien of its mortgage indenture. |
| |
(b) | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
Rate stabilization bonds |
|
| | 5.82 | % | | 2017 | | $ | — |
| | $ | 41 |
| |
Unsecured notes | 2.40 | % | - | 6.35 | % | | 2021 - 2047 | | 2,600 |
| | 2,300 |
| 2.40 | % | - | 6.35 | % | | 2021 - 2048 | | 2,900 |
| | 2,600 |
|
Total long-term debt | | | | | 2,600 |
| | 2,341 |
| | | | | 2,900 |
| | 2,600 |
|
Unamortized debt discount and premium, net | | | | | (6 | ) | | (4 | ) | | | | | (6 | ) | | (6 | ) |
Unamortized debt issuance costs | | | | | (17 | ) | | (15 | ) | | | | | (18 | ) | | (17 | ) |
Long-term debt due within one year | | | | | — |
| | (41 | ) | |
Long-term debt | | | | | $ | 2,577 |
| | $ | 2,281 |
| | | | | $ | 2,876 |
| | $ | 2,577 |
|
Long-term debt to financing trusts(a) | | | | | | | | |
Subordinated debentures to BGE Capital Trust II | | | 6.20 | % | | 2043 | | $ | — |
| | $ | 258 |
| |
Total long-term debt to financing trusts | | | | | — |
| | 258 |
| |
Unamortized debt issuance costs | | | | | — |
| | (6 | ) | |
Long-term debt to financing trusts | | | | | $ | — |
| | $ | 252 |
| |
__________
| |
(a) | Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within BGE’s Consolidated Balance Sheets. On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities (“Securities”), pursuant to the optional redemption provisions of the Indenture under which the Securities were issued. The redemption price per share was $25.19, which equaled the stated value per share plus accrued and unpaid dividends to, but excluding, the redemption date. No dividends on the Securities redeemed were accrued on or after the redemption date, nor did any interest accrue on amounts held to pay the redemption price. |
PHI
|
| | | | | | | | | | | | | | | |
| | | | | | | Successor |
| | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 |
Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 3.05 | % | - | 7.90 | % | | 2018 - 2045 | | $ | 4,743 |
| | $ | 4,569 |
|
Senior unsecured notes |
|
|
| 7.45 | % | | 2017 - 2032 | | 185 |
| | 266 |
|
Unsecured Tax-Exempt Bonds | | | 5.40 | % | | 2031 | | 112 |
| | 112 |
|
Medium-Terms Notes (unsecured) | 6.81 | % | - | 7.72 | % | | 2018 - 2027 | | 26 |
| | 40 |
|
Transition bonds(b) | 5.05 | % | - | 5.55 | % | | 2020 - 2023 | | 90 |
| | 124 |
|
Notes payable and other (c) | 6.20 | % | - | 8.88 | % | | 2018 - 2022 | | 33 |
| | 46 |
|
Total long-term debt | | | | | | | 5,189 |
|
| 5,157 |
|
Unamortized debt discount and premium, net | | | | | | | 5 |
| | 1 |
|
Unamortized debt issuance costs | | | | | | | (6 | ) | | (2 | ) |
Fair value adjustment | | | | | | | 686 |
| | 742 |
|
Long-term debt due within one year | | | | | | | (396 | ) | | (253 | ) |
Long-term debt | | | | | | | $ | 5,478 |
|
| $ | 5,645 |
|
|
| | | | | | | | | | | | | | | |
| | | | | Maturity Date | | December 31, |
| Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | |
First mortgage bonds(a) | 1.81 | % | - | 7.90 | % | | 2021 - 2048 | | $ | 5,242 |
| | $ | 4,743 |
|
Senior unsecured notes | |
| 7.45 | % | | 2032 | | 185 |
| | 185 |
|
Unsecured Tax-Exempt Bonds | 1.74 | % | - | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
|
Medium-terms notes (unsecured) | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
Transition bonds(b) |
|
|
| 5.55 | % | | 2023 | | 59 |
| | 90 |
|
Notes payable and other (c) | 7.28 | % | - | 8.88 | % | | 2019 - 2022 | | 16 |
| | 33 |
|
Total long-term debt | | | | | | | 5,636 |
|
| 5,189 |
|
Unamortized debt discount and premium, net | | | | | | | 4 |
| | 5 |
|
Unamortized debt issuance costs | | | | | | | (14 | ) | | (6 | ) |
Fair value adjustment | | | | | | | 633 |
| | 686 |
|
Long-term debt due within one year | | | | | | | (125 | ) | | (396 | ) |
Long-term debt | | | | | | | $ | 6,134 |
|
| $ | 5,478 |
|
__________
| |
(a) | Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture. |
| |
(b) | Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets. |
| |
(c) | Includes Pepco's capital lease obligations of $27$14 million and $39$27 million at December 31, 20172018 and 2016,2017, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
First mortgage bonds(a) | 3.05 | % | - | 7.90 | % | | 2022 - 2043 | | $ | 2,535 |
| | $ | 2,335 |
| 3.05 | % | - | 7.90 | % | | 2022 - 2048 | | $ | 2,735 |
| | $ | 2,535 |
|
Notes payable and other(b) | 6.20 | % | - | 8.88 | % | | 2018 - 2022 | | 35 |
| | 46 |
| 7.28 | % | - | 8.88 | % | | 2019 - 2022 | | 16 |
| | 35 |
|
Total long-term debt | | | | | 2,570 |
|
| 2,381 |
| | | | | 2,751 |
|
| 2,570 |
|
Unamortized debt discount and premium, net | | | | | 2 |
| | (2 | ) | | | | | 2 |
| | 2 |
|
Unamortized debt issuance costs | | | | | (32 | ) | | (30 | ) | | | | | (34 | ) | | (32 | ) |
Long-term debt due within one year | | | | | (19 | ) | | (16 | ) | | | | | (15 | ) | | (19 | ) |
Long-term debt | | | | | $ | 2,521 |
|
| $ | 2,333 |
| | | | | $ | 2,704 |
|
| $ | 2,521 |
|
__________
| |
(a) | Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture. |
| |
(b) | Includes capital lease obligations of $27$14 million and $39$27 million at December 31, 20172018 and 2016,2017, respectively. Lease payments of $13 million and $14 million will be made in 2018 and 2019, respectively.2019. |
DPL
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
First mortgage bonds(a) | 3.50 | % | - | 4.15 | % | | 2023 - 2045 | | $ | 1,171 |
| | $ | 1,196 |
| 1.81 | % | - | 4.27 | % | | 2023 - 2048 | | $ | 1,370 |
| | $ | 1,171 |
|
Unsecured Tax-Exempt Bonds | | | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
| 1.74 | % | - | 5.40 | % | | 2024 - 2031 | | 112 |
| | 112 |
|
Medium-Terms Notes (unsecured) | 6.81 | % | - | 7.72 | % | | 2018 - 2027 | | 26 |
| | 40 |
| |
Medium-terms notes (unsecured) | | 7.61 | % | - | 7.72 | % | | 2019 - 2027 | | 22 |
| | 26 |
|
Total long-term debt | | | | | 1,309 |
|
| 1,348 |
| | | | | 1,504 |
|
| 1,309 |
|
Unamortized debt discount and premium, net | | | | | 2 |
| | 2 |
| | | | | 2 |
| | 2 |
|
Unamortized debt issuance costs | | | | | (11 | ) | | (10 | ) | | | | | (12 | ) | | (11 | ) |
Long-term debt due within one year | | | | | (83 | ) | | (119 | ) | | | | | (91 | ) | | (83 | ) |
Long-term debt | | | | | $ | 1,217 |
|
| $ | 1,221 |
| | | | | $ | 1,403 |
|
| $ | 1,217 |
|
__________
| |
(a) | Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture. |
ACE
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
First mortgage bonds(a) | 3.38 | % | - | 7.75 | % | | 2018 - 2036 | | $ | 1,037 |
| | $ | 1,038 |
| 3.38 | % | - | 6.80 | % | | 2021 - 2036 | | $ | 1,137 |
| | $ | 1,037 |
|
Transition bonds(b) | 5.05 | % | - | 5.55 | % | | 2020 - 2023 | | 90 |
| | 124 |
|
| | 5.55 | % | | 2023 | | 59 |
| | 90 |
|
Total long-term debt | | | | | 1,127 |
|
| 1,162 |
| | | | | 1,196 |
|
| 1,127 |
|
Unamortized debt discount and premium, net | | | | | (1 | ) | | (1 | ) | | | | | (1 | ) | | (1 | ) |
Unamortized debt issuance costs | | | | | (5 | ) | | (6 | ) | | | | | (7 | ) | | (5 | ) |
Long-term debt due within one year | | | | | (281 | ) | | (35 | ) | | | | | (18 | ) | | (281 | ) |
Long-term debt | | | | | $ | 840 |
|
| $ | 1,120 |
| | | | | $ | 1,170 |
|
| $ | 840 |
|
__________
| |
(a) | Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture. |
| |
(b) | Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | Maturities of ACE's Transition Bonds outstanding at December 31, 2017 are $31 million in 2018, $18 million in 2019, $20 million in 2020 and $21 million in 2021. |
Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 20182019 through 20222023 and thereafter are as follows:
| | Year | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
2018 | $ | 2,075 |
| | $ | 346 |
| | $ | 840 |
| | $ | 500 |
| | $ | — |
| | $ | 383 |
| | $ | 19 |
| | $ | 83 |
| | $ | 281 |
| |
2019 | 959 |
| | 615 |
| | 300 |
| | — |
| | — |
| | 44 |
| | 14 |
| | 12 |
| | 18 |
| $ | 1,349 |
| | $ | 906 |
| | $ | 300 |
| | $ | — |
| | $ | — |
| | $ | 125 |
| | $ | 15 |
| | $ | 91 |
| | $ | 18 |
|
2020 | 3,564 |
| | 2,144 |
| | 500 |
| | — |
| | — |
| | 20 |
| | — |
| | — |
| | 20 |
| 3,528 |
| | 2,108 |
| | 500 |
| | — |
| | — |
| | 20 |
| | — |
| | — |
| | 20 |
|
2021 | 1,513 |
| | 1 |
| | 350 |
| | 300 |
| | 300 |
| | 262 |
| | 2 |
| | — |
| | 260 |
| 1,511 |
| | 1 |
| | 350 |
| | 300 |
| | 300 |
| | 261 |
| | 1 |
| | — |
| | 260 |
|
2022 | 3,084 |
| | 1,024 |
| | — |
| | 350 |
| | 250 |
| | 310 |
| | 310 |
| | — |
| | — |
| 3,084 |
| | 1,024 |
| | — |
| | 350 |
| | 250 |
| | 310 |
| | 310 |
| | — |
| | — |
|
2023 | | 850 |
| | — |
| | — |
| | 50 |
| | 300 |
| | 500 |
| | — |
| | 500 |
| | — |
|
Thereafter | 22,852 |
| (a) | 4,825 |
| | 5,892 |
| (b) | 1,959 |
| (c) | 2,050 |
| | 4,170 |
| | 2,225 |
| | 1,214 |
| | 548 |
| 24,979 |
| (a) | 4,720 |
| | 7,243 |
| (b) | 2,609 |
| (c) | 2,050 |
| | 4,420 |
| | 2,425 |
| | 913 |
| | 898 |
|
Total | $ | 34,047 |
| | $ | 8,955 |
| | $ | 7,882 |
| | $ | 3,109 |
|
| $ | 2,600 |
|
| $ | 5,189 |
|
| $ | 2,570 |
|
| $ | 1,309 |
|
| $ | 1,127 |
| $ | 35,301 |
| | $ | 8,759 |
| | $ | 8,393 |
| | $ | 3,309 |
|
| $ | 2,900 |
|
| $ | 5,636 |
|
| $ | 2,751 |
|
| $ | 1,504 |
|
| $ | 1,196 |
|
__________
| |
(a) | Includes $390 million due to ComEd and PECO financing trusts. |
| |
(b) | Includes $206 million due to ComEd financing trust. |
| |
(c) | Includes $184 million due to PECO financing trusts. |
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of December 31, 2017. See Note 2120 — Earnings Per Share for furtheradditional information on the issuance of common stock.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $3$2.9 billion of generating assets have been pledged as collateral at December 31, 2017.2018. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.
Denver Airport.In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado. The agreement is scheduled to mature on
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2017,2018, $6 million was outstanding.
CEU Upstream.In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties. 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.
In December 2016, substantially all of the Upstream natural gas and oil exploration and production assets were sold for $37 million. The proceeds were used to reduce the debt balance by $31 million. The remaining proceeds
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
of $6 million were being held in escrow. In addition, during 2016, $15 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $22 million at December 31, 2016. During 2017, additional assets were sold for $1 million and the remaining $6 million in escrow was released and applied to the debt balance resulting in an outstanding amount of $15 million at December 31, 2017. Upon final resolution, CEU Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. At December 31, 2017,2018, the outstanding debt balance of $15 million was classified within Long term debt due within one year onin Exelon’s and Generation’s Consolidated Balance Sheets. See Note 45 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of Long-Lived Assets and Intangibles for additional information.
Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2017, $92018, $8 million was outstanding.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in the first half of 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2017, $5302018, $508 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2017,2018, Generation had $105$38 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2017, $5122018, $479 million was outstanding.
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2017,2018, the Continental Wind letter of credit facility had $114 million in letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 2 - Variable Interest Entities for additional information on EGRP.
ExGen Texas Power. In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan was scheduled to
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
mature on September 18, 2021. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants.
On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders, which permitted EGTP to draw on its revolving credit facility and initiate an orderly sales process of its assets. On November 7, 2017, the debtors filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result, Exelon and Generation deconsolidated the nonrecourse senior secured term loan, the revolving credit facility, and the interest rate swaps from their consolidated financial statements as of December 31, 2017. Due to their nonrecourse nature, these borrowings are secured solely by the assets of EGTP and its subsidiaries.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to EGTP's lenders. See Note 5 — Mergers, Acquisitions and Dispositions for additional information on EGTP.
Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2017, $1272018, $115 million was outstanding.
In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 2 - Variable interest Entities for additional information on EGRP.
SolGen. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2017, $1472018, $137 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash onin Exelon’s and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2017, $8502018, $834 million was outstanding. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing. See Note 2 - Variable interest Entities for additional information on EGRP.
14. Income Taxes (All Registrants)
Corporate Tax Reform (All Registrants)
On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21%; (2) creating a 30% limitation on deductible interest expense (not applicable to regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production activities deduction; (5) eliminating the corporate alternative minimum tax and changing how existing alternative minimum tax credits can be realized; and (6) changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant change that impacts the Registrants is the reduction of the corporate federal income tax rate from 35% to 21% beginning January 1, 2018.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pursuant to the enactment of the TCJA, the Registrants remeasured their existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while the Utility Registrants recorded corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery through customer rates and an adjustment to income tax expense for all other amounts. The amount and timing of potential settlements of the established net regulatory liabilities will beare determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 34 — Regulatory Matters for further information.additional information regarding settlements for passing back of TCJA income tax savings benefits to customers.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Registrants have completed their assessment of the majority ofassessed the applicable provisions in the TCJA and have recorded the associated impacts as of December 31, 2017. As discussed further below,The Registrants recorded provisional income tax amounts as of December 31, 2017, as allowed under SAB 118 issued by the SEC in December 2017, the Registrants have recorded provisional income tax amounts as of December 31, 2017 for changes pursuant to the TCJA related to depreciation for whichbecause the impacts could not be finalized upon issuance of the Registrants’ financial statements, but for which reasonable estimates could be determined.
ForOn August 3, 2018, the U.S. Department of Treasury, in conjunction with the IRS, released proposed regulations clarifying the immediate expensing provisions enacted by the TCJA, specifically that regulated utility property acquired and placed-in-service after September 27, 2017, the TCJA repeals 50% bonus depreciation for all taxpayers and placed in addition provides for 100% expensing for taxpayers other than regulated utilities. As a result, Generation will be required to evaluate the contractual terms of its fourth quarter 2017 capital additions and determine if they qualify for 100% expensing under the TCJA as compared to 50% bonus depreciation under prior tax law. Similarly, the Utility Registrants will be required to evaluate the contractual terms of their fourth quarter 2017 capital additions to determine whether they still qualify for the prior tax law’s 50% bonus depreciation as compared to no bonus depreciation pursuant to the TCJA. As ofservice by December 31, 2017, qualifies for 100% expensing. Until the proposed regulations are finalized, taxpayers may rely on the proposed regulations for tax years ending after September 28, 2017. The Registrants have not completed this analysis but were able to record a reasonable estimate ofrecorded the effectsimpact of these changes based on capital costs incurred at each ofproposed regulations and the Registrants prior to and after the beginning of the fourth quarter of 2017.
At Generation, any required changes to the provisional estimates during the measurement period related to the above item would result in an adjustment to current income tax expense at 35% and a corresponding adjustment to deferred income tax expense at 21% and such changes could be material to Generation’s future results of operations. At the Utility Registrants, any required changes to the provisional estimates would result in the recording of regulatory assets or liabilities to the extent such amounts are probable of settlement or recovery through customer rates and a net change to income tax expense for any other amounts.
The Registrants expect any final adjustments to the provisional amounts to be recorded by the third quarter of 2018, which could be material to the Registrants’ future results of operations or financial positions. The accounting for all other applicable provisions of the TCJA is considered complete based on our current interpretation of the provisions of the TCJA as enacted as of December 31, 2017.was immaterial.
While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected that technical corrections or other formsthe U.S. Department of Treasury and the IRS will issue additional interpretative guidance will be issued during 2018, whichin the future that could result in material changes to previously finalized provisions. At this time, mostmany of the states in which Exelon does business have not providedissued guidance regarding TCJA impacts and may issue guidance in 2018 which maythe impact estimates.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
was not material.
The one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of December 31, 2017 are presented below:
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon(b) | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net Decrease to Deferred Income Tax Liability Balances
| $8,624 | | $1,895 | | $2,819 | | $1,407 | | $1,120 | | $1,944 | | $968 | | $540 | | $456 |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO(c) | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net Regulatory Liability Recorded(a) | $7,315 | | N/A | | $2,818 | | $1,394 | | $1,124 | | $1,979 | | $976 | | $545 | | $458 |
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon(b) | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Net Deferred Income Tax Benefit/(Expense) Recorded | $1,309 | | $1,895 | | $1 | | $13 | | $(4) | | $(35) | | $(8) | | $(5) | | $(2) |
__________
| |
(a) | Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with customers. |
| |
(b) | Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation plans. |
| |
(c) | Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remainsremained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. Refer to Note 3 - Regulatory Matters for additional information. |
The net regulatory liabilities above include (1) amounts subject to IRS “normalization” rules that are required to be passed back to customers generally over the remaining useful life of the underlying assets giving rise to the associated deferred income taxes, and (2) amounts for which the timing of settlement with customers is subject to determinations by the rate regulators. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the income tax benefits associated with the ultimate settlement with customers.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Successor | | | | | | |
| Exelon | | ComEd | | PECO(a) | | BGE | | PHI | | PEPCO | | DPL | | ACE |
Subject to IRS Normalization Rules | $3,040 | | $1,400 | | $533 | | $459 | | $648 | | $299 | | $195 | | $153 |
Subject to Rate Regulator Determination | 1,694 | | 573 | | 43 | | 324 | | 754 | | 391 | | 194 | | 170 |
|
Net Regulatory Liabilities | $4,734 | | $1,973 | | $576 | | $783 | | $1,402 | | $690 | | $389 | | $ | 323 |
|
_________ | |
(a) | Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remainswas in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate regulators are lower relative to the other Utility Registrants. Refer to Note 3 - Regulatory Matters for additional information. |
The net regulatory liability amounts subject to the IRS normalization rules generally relate to property, plant and equipment with remaining useful lives ranging from 30 to 40 years across the Utility Registrants. For the other amounts, rate regulators could require the passing back of amounts to customers over shorter time frames.
Combined Notes to Consolidated Financial Statements See Note 4 - (Continued)Regulatory Matters for additional information.
(Dollars in millions, except per share data unless otherwise noted)
Components of Income Tax Expense or Benefit
Income tax expense (benefit) from continuing operations is comprised of the following components:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2017 | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Included in operations: | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | |
Current | $ | 194 |
| | $ | 584 |
| | $ | (191 | ) | | $ | 71 |
| | $ | 74 |
| | $ | (60 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (12 | ) |
Deferred | (469 | ) | | (2,003 | ) | | 523 |
| | 28 |
| | 101 |
| | 250 |
| | 114 |
| | 82 |
| | 34 |
|
Investment tax credit amortization | (25 | ) | | (21 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
|
State | | | | | | | | | | | | | | | | |
|
Current | 14 |
| | 65 |
| | (49 | ) | | 14 |
| | (5 | ) | | (4 | ) | | (2 | ) | | — |
| | — |
|
Deferred | 161 |
| | — |
| | 136 |
| | (9 | ) | | 49 |
| | 32 |
| | 13 |
| | 13 |
| | 4 |
|
Total | $ | (125 | ) | | $ | (1,375 | ) | | $ | 417 |
| | $ | 104 |
| | $ | 218 |
| | $ | 217 |
| | $ | 105 |
| | $ | 71 |
| | $ | 26 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the Year Ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Included in operations: | | | | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | | | | |
Current | $ | 60 |
| | $ | 513 |
| | $ | (135 | ) | | $ | 63 |
| | $ | 51 |
| | $ | (118 | ) | | $ | (88 | ) | | $ | (26 | ) | | $ | (281 | ) | | | $ | — |
|
Deferred | 607 |
| | (247 | ) | | 379 |
| | 72 |
| | 88 |
| | 136 |
| | 97 |
| | 22 |
| | 283 |
| | | 10 |
|
Investment tax credit amortization | (24 | ) | | (20 | ) | | (2 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | | | — |
|
State | | | | | | | | | | | | | | | | | | | |
|
Current | 39 |
| | 45 |
| | (4 | ) | | 9 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| | (11 | ) | | | — |
|
Deferred | 79 |
| | (1 | ) | | 63 |
| | 5 |
| | 31 |
| | 16 |
| | 12 |
| | — |
| | 13 |
| | | 7 |
|
Total | $ | 761 |
| | $ | 290 |
| | $ | 301 |
| | $ | 149 |
| | $ | 174 |
| | $ | 41 |
| | $ | 22 |
| | $ | (4 | ) | | $ | 3 |
| | | $ | 17 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2015 |
| | | | | | | | | | | Predecessor
| | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Included in operations: | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | |
Current | $ | 407 |
| | $ | 546 |
| | $ | (80 | ) | | $ | 64 |
| | $ | 25 |
| | $ | 12 |
| | $ | (54 | ) | | $ | (27 | ) | | $ | (2 | ) |
Deferred | 566 |
| | 16 |
| | 310 |
| | 69 |
| | 126 |
| | 103 |
| | 126 |
| | 73 |
| | 27 |
|
Investment tax credit amortization | (22 | ) | | (19 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
|
State | | | | | | | | | | | | | | | | | |
Current | (86 | ) | | (90 | ) | | 7 |
| | (10 | ) | | — |
| | 17 |
| | 6 |
| | 2 |
| | 3 |
|
Deferred | 208 |
| | 49 |
| | 45 |
| | 20 |
| | 39 |
| | 32 |
| | 24 |
| | 1 |
| | 5 |
|
Total | $ | 1,073 |
|
| $ | 502 |
|
| $ | 280 |
|
| $ | 143 |
|
| $ | 189 |
|
| $ | 163 |
|
| $ | 102 |
|
| $ | 49 |
|
| $ | 33 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following: |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Included in operations: | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | |
Current | $ | 226 |
| | $ | 337 |
| | $ | (63 | ) | | $ | 11 |
| | $ | (5 | ) | | $ | (4 | ) | | $ | 28 |
| | $ | (3 | ) | | $ | (14 | ) |
Deferred | (98 | ) | | (347 | ) | | 145 |
| | 10 |
| | 47 |
| | 24 |
| | (21 | ) | | 13 |
| | 18 |
|
Investment tax credit amortization | (24 | ) | | (21 | ) | | (2 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
State | | | | | | | | | | | | | | | | | |
Current | (1 | ) | | 6 |
| | (29 | ) | | 1 |
| | — |
| | 7 |
| | — |
| | — |
| | — |
|
Deferred | 17 |
| | (83 | ) | | 117 |
| | (16 | ) | | 32 |
| | 9 |
| | 6 |
| | 12 |
| | 8 |
|
Total | $ | 120 |
| | $ | (108 | ) | | $ | 168 |
| | $ | 6 |
| | $ | 74 |
| | $ | 35 |
| | $ | 13 |
| | $ | 22 |
| | $ | 12 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
U.S. Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % |
Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
State income taxes, net of Federal income tax benefit | 2.3 |
| | 3.0 |
| | 5.7 |
| | 0.6 |
| | 5.4 |
| | 4.8 |
| | 3.2 |
| | 5.4 |
| | 5.6 |
|
Qualified nuclear decommissioning trust fund income | 3.8 |
| | 10.0 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of investment tax credit, including deferred taxes on basis difference | (0.9 | ) | | (2.2 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.2 | ) | | (0.4 | ) |
Plant basis differences(a) | (1.7 | ) | | — |
| | 0.3 |
| | (13.8 | ) | | 0.1 |
| | 1.1 |
| | (0.4 | ) | | 2.0 |
| | 3.6 |
|
Production tax credits and other credits | (1.8 | ) | | (4.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Noncontrolling interests | 0.1 |
| | 0.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Like-kind exchange | (1.2 | ) | | — |
| | 1.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Merger expenses | (3.7 | ) | | (1.3 | ) | | — |
| | — |
| | — |
| | (9.5 | ) | | (6.3 | ) | | (7.8 | ) | | (19.8 | ) |
FitzPatrick bargain purchase gain | (2.2 | ) | | (5.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Tax Cut and Jobs Act of 2017(b) | (33.1 | ) | | (130.1 | ) | | 0.1 |
| | (2.3 | ) | | 0.9 |
| | 6.4 |
| | 2.7 |
| | 2.5 |
| | 1.6 |
|
Other | 0.1 |
| | (0.4 | ) | | 0.2 |
| | (0.1 | ) | | 0.2 |
| | (0.1 | ) | | (0.2 | ) | | 0.1 |
| | (0.4 | ) |
Effective income tax rate | (3.3 | )% | | (96.2 | )% | | 42.4 | % | | 19.3 | % | | 41.5 | % | | 37.5 | % | | 33.9 | % | | 37.0 | % | | 25.2 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2017(a) | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Included in operations: | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | |
Current | $ | 194 |
| | $ | 584 |
| | $ | (191 | ) | | $ | 71 |
| | $ | 74 |
| | $ | (60 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (12 | ) |
Deferred | (471 | ) | | (2,005 | ) | | 523 |
| | 28 |
| | 101 |
| | 250 |
| | 114 |
| | 82 |
| | 34 |
|
Investment tax credit amortization | (25 | ) | | (21 | ) | | (2 | ) | | — |
| | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
|
State | | | | | | | | | | | | | | | | |
|
Current | 14 |
| | 65 |
| | (49 | ) | | 14 |
| | (5 | ) | | (4 | ) | | (2 | ) | | — |
| | — |
|
Deferred | 162 |
| | 1 |
| | 136 |
| | (9 | ) | | 49 |
| | 32 |
| | 13 |
| | 13 |
| | 4 |
|
Total | $ | (126 | ) | | $ | (1,376 | ) | | $ | 417 |
| | $ | 104 |
| | $ | 218 |
| | $ | 217 |
| | $ | 105 |
| | $ | 71 |
| | $ | 26 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the Year Ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL (c) | | ACE (c) | | PHI (c) | | | 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 (d) | 3.3 |
| | 3.3 |
| | 5.6 |
| | 1.3 |
| | 5.0 |
| | 15.7 |
| | 52.7 |
| | 6.2 |
| | 5.8 |
| | | 11.9 |
|
Qualified nuclear decommissioning trust fund income | 3.4 |
| | 7.8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (2.3 | ) | | (0.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (3.7 | ) | | 0.8 |
| | 1.4 |
| | | (0.9 | ) |
Plant basis differences | (4.8 | ) | | — |
| | (0.6 | ) | | (9.6 | ) | | (2.7 | ) | | (22.8 | ) | | (25.5 | ) | | 10.3 |
| | 39.0 |
| | | (13.5 | ) |
Production tax credits and other credits | (3.6 | ) | | (8.2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Noncontrolling interests | (0.2 | ) | | (0.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Statute of limitations expiration | (0.4 | ) | | (1.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Penalties | 1.9 |
| | — |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (0.7 | ) | | | — |
|
Merger Expenses | 5.5 |
| | 1.1 |
| | — |
| | — |
| | — |
| | 23.5 |
| | 112.9 |
| | (44.9 | ) | | (89.0 | ) | | | 11.1 |
|
Other (e) | (0.6 | ) | | (1.5 | ) | | 0.1 |
| | (1.2 | ) | | — |
| | (1.8 | ) | | (2.2 | ) | | 1.3 |
| | 3.3 |
| | | 3.6 |
|
Effective income tax rate | 38.3 | % | | 33.2 | % | | 44.3 | % | | 25.4 | % | | 37.2 | % |
| 49.4 | % |
| 169.2 | % |
| 8.7 | % |
| (5.2 | )% |
| | 47.2 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the Year Ended December 31, 2016(a) | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Included in operations: | | | | | | | | | | | | | | | | | | | | |
Federal | | | | | | | | | | | | | | | | | | | | |
Current | $ | 60 |
| | $ | 513 |
| | $ | (135 | ) | | $ | 63 |
| | $ | 51 |
| | $ | (118 | ) | | $ | (88 | ) | | $ | (26 | ) | | $ | (281 | ) | | | $ | — |
|
Deferred | 600 |
| | (254 | ) | | 379 |
| | 72 |
| | 88 |
| | 136 |
| | 97 |
| | 22 |
| | 283 |
| | | 10 |
|
Investment tax credit amortization | (24 | ) | | (20 | ) | | (2 | ) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) | | | — |
|
State | | | | | | | | | | | | | | | | | | | |
|
Current | 39 |
| | 45 |
| | (4 | ) | | 9 |
| | 5 |
| | 7 |
| | 1 |
| | — |
| | (11 | ) | | | — |
|
Deferred | 78 |
| | (2 | ) | | 63 |
| | 5 |
| | 31 |
| | 16 |
| | 12 |
| | — |
| | 13 |
| | | 7 |
|
Total | $ | 753 |
| | $ | 282 |
| | $ | 301 |
| | $ | 149 |
| | $ | 174 |
| | $ | 41 |
| | $ | 22 |
| | $ | (4 | ) | | $ | 3 |
| | | $ | 17 |
|
__________
| |
(a) | Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. Components of income tax expense or benefit are recast to reflect the impact of the new standard. |
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, 2018 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
U.S. Federal statutory rate | 21.0 | % |
| 21.0 | % |
| 21.0 | % |
| 21.0 | % |
| 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % | | 21.0 | % |
Increase (decrease) due to: | | | | | | | | | | | | | | | | | |
State income taxes, net of Federal income tax benefit | 0.6 |
| | (16.6 | ) | | 8.3 |
| | (2.6 | ) | | 6.6 |
| | 3.0 |
| | 2.2 |
| | 6.7 |
| | 7.4 |
|
Qualified NDT fund income | (1.9 | ) | | (11.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (6.5 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.3 | ) | | (0.4 | ) |
Plant basis differences | (3.5 | ) | | — |
| | (0.2 | ) | | (14.1 | ) | | (1.3 | ) | | (1.6 | ) | | (2.7 | ) | | (0.3 | ) | | (0.5 | ) |
Production tax credits and other credits | (2.2 | ) | | (13.5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Noncontrolling interests | (1.0 | ) | | (6.1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Excess deferred tax amortization | (8.3 | ) | | — |
| | (9.1 | ) | | (3.2 | ) | | (8.0 | ) | | (14.5 | ) | | (14.8 | ) | | (12.0 | ) | | (14.9 | ) |
Tax Cuts and Jobs Act of 2017 | 0.9 |
| | 2.7 |
| | (0.1 | ) | | — |
| | — |
| | 0.1 |
| | — |
| | — |
| | — |
|
Other | 1.0 |
| | 1.3 |
| | 0.5 |
| | 0.3 |
| | 0.9 |
| | 0.3 |
| | 0.2 |
| | 0.4 |
| | 1.2 |
|
Effective income tax rate | 5.4 | % | | (29.5 | )% | | 20.2 | % | | 1.3 | % | | 19.1 | % | | 8.1 | % | | 5.8 | % | | 15.5 | % | | 13.8 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | For the Year Ended December 31, 2015 | For the Year Ended December 31, 2017(a) |
| | | | | | | | | | | Predecessor | | | | | | | | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | 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 | % | 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 | 3.7 |
| | 1.0 |
| | 4.9 |
| | 1.0 |
| | 5.3 |
| | 6.6 |
| | 6.7 |
| | 1.7 |
| | 5.7 |
| 2.3 |
| | 2.9 |
| | 5.7 |
| | 0.6 |
| | 5.4 |
| | 4.8 |
| | 3.2 |
| | 5.4 |
| | 5.6 |
|
Qualified nuclear decommissioning trust fund loss | (0.4 | ) | | (0.8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Domestic production activities deduction | (0.7 | ) | | (1.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Health care reform legislation | — |
| | — |
| | — |
| | — |
| | 0.1 |
| | — |
| | — |
| | — |
| | — |
| |
Qualified NDT fund income | | 3.8 |
| | 9.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of investment tax credit, including deferred taxes on basis difference | (0.9 | ) | | (1.5 | ) | | (0.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.4 | ) | | (0.6 | ) | (0.9 | ) | | (2.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (0.1 | ) | | (0.2 | ) | | (0.4 | ) |
Plant basis differences | (1.5 | ) | | — |
| | (0.1 | ) | | (8.7 | ) | | (0.7 | ) | | (4.3 | ) | | (5.8 | ) | | (2.3 | ) | | (1.3 | ) | |
Plant basis differences(b) | | (1.7 | ) | | — |
| | 0.3 |
| | (13.8 | ) | | 0.1 |
| | 1.1 |
| | (0.4 | ) | | 2.0 |
| | 3.6 |
|
Production tax credits and other credits | (1.9 | ) | | (3.4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (1.8 | ) | | (4.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Noncontrolling interests | 0.3 |
| | 0.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Statute of limitations expiration
| (1.4 | ) | | (2.4 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Like-kind exchange | | (1.2 | ) | | — |
| | 1.3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Merger expenses | | (3.6 | ) | | (1.2 | ) | | — |
| | — |
| | — |
| | (9.5 | ) | | (6.3 | ) | | (7.8 | ) | | (19.8 | ) |
FitzPatrick bargain purchase gain | | (2.2 | ) | | (5.6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Tax Cuts and Jobs Act of 2017(c) | | (33.1 | ) | | (128.3 | ) | | 0.1 |
| | (2.3 | ) | | 0.9 |
| | 6.4 |
| | 2.7 |
| | 2.5 |
| | 1.6 |
|
Other (f) | — |
| | — |
| | 0.2 |
| | 0.2 |
| | — |
| | (3.2 | ) | | (0.5 | ) | | 5.2 |
| | 6.4 |
| 0.1 |
| | (0.5 | ) | | 0.2 |
| | (0.1 | ) | | 0.2 |
| | (0.1 | ) | | (0.2 | ) | | 0.1 |
| | (0.4 | ) |
Effective income tax rate | 32.2 | % |
| 27.1 | % |
| 39.7 | % |
| 27.4 | % |
| 39.6 | % |
| 33.9 | % |
| 35.3 | % |
| 39.2 | % |
| 45.2 | % | (3.3 | )% | | (94.6 | )% | | 42.4 | % | | 19.3 | % | | 41.5 | % | | 37.5 | % | | 33.9 | % | | 37.0 | % | | 25.2 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the Year Ended December 31, 2016(a) | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL (d) | | ACE (d) | | PHI (d) | | | PHI |
U.S. Federal statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | 35.0 | % | | | 35.0 | % |
Increase (decrease) due to: | | | | | | | | | | | | | | | | | | | |
|
State income taxes, net of Federal income tax benefit (e) | 3.3 |
| | 3.2 |
| | 5.6 |
| | 1.3 |
| | 5.0 |
| | 15.7 |
| | 52.7 |
| | 6.2 |
| | 5.8 |
| | | 11.9 |
|
Qualified NDT fund income | 3.4 |
| | 7.9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of investment tax credit, including deferred taxes on basis difference | (1.2 | ) | | (2.3 | ) | | (0.3 | ) | | (0.1 | ) | | (0.1 | ) | | (0.2 | ) | | (3.7 | ) | | 0.8 |
| | 1.4 |
| | | (0.9 | ) |
Plant basis differences | (4.9 | ) | | — |
| | (0.6 | ) | | (9.6 | ) | | (2.7 | ) | | (22.8 | ) | | (25.5 | ) | | 10.3 |
| | 39.0 |
| | | (13.5 | ) |
Production tax credits and other credits | (3.6 | ) | | (8.3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Noncontrolling interests | (0.2 | ) | | (0.6 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Statute of limitations expiration | (0.4 | ) | | (1.7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Penalties | 1.9 |
| | — |
| | 4.5 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (0.7 | ) | | | — |
|
Merger Expenses | 5.6 |
| | 1.1 |
| | — |
| | — |
| | — |
| | 23.5 |
| | 112.9 |
| | (44.9 | ) | | (89.0 | ) | | | 11.1 |
|
Other (f) | (0.7 | ) | | (1.4 | ) | | 0.1 |
| | (1.2 | ) | | — |
| | (1.8 | ) | | (2.2 | ) | | 1.3 |
| | 3.3 |
| | | 3.6 |
|
Effective income tax rate | 38.2 | % | | 32.9 | % | | 44.3 | % | | 25.4 | % | | 37.2 | % |
| 49.4 | % |
| 169.2 | % |
| 8.7 | % |
| (5.2 | )% |
| | 47.2 | % |
__________
| |
(a) | Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax rates are recast to reflect the impact of the new standard. |
| |
(b) | Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively (See Footnote 3respectively. See Note 4 - Regulatory Matters).Matters for additional information. |
| |
(b)(c) | Included are impacts for TJCATCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback. |
| |
(c)(d) | DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented. |
| |
(d)(e) | Includes a remeasurement of uncertain state income tax positions for Pepco and DPL. |
| |
(e)(f) | At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016. |
| |
(f) | Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE and PHI. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 20172018 and 20162017 are presented below:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2017 (a) |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Plant basis differences | $ | (12,490 | ) | | $ | (2,819 | ) | | $ | (3,825 | ) | | $ | (1,762 | ) | | $ | (1,368 | ) | | $ | (2,521 | ) | | $ | (1,152 | ) | | $ | (717 | ) | | $ | (607 | ) |
Accrual based contracts | 150 |
| | (66 | ) | | — |
| | — |
| | — |
| | 216 |
| | — |
| | — |
| | — |
|
Derivatives and other financial instruments | (85 | ) | | (66 | ) | | (2 | ) | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Deferred pension and postretirement obligation | 1,463 |
| | (205 | ) | | (285 | ) | | (15 | ) | | (29 | ) | | (130 | ) | | (78 | ) | | (51 | ) | | (18 | ) |
Nuclear decommissioning activities | (553 | ) | | (553 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deferred debt refinancing costs | 217 |
| | 26 |
| | (8 | ) | | (1 | ) | | (3 | ) | | 203 |
| | (4 | ) | | (2 | ) | | (1 | ) |
Regulatory assets and liabilities | (688 | ) | | — |
| | 489 |
| | (90 | ) | | 136 |
| | (184 | ) | | 39 |
| | 88 |
| | 86 |
|
Tax loss carryforward | 344 |
| | 76 |
| | 33 |
| | 9 |
| | 11 |
| | 156 |
| | 40 |
| | 68 |
| | 35 |
|
Tax credit carryforward | 861 |
| | 868 |
| | 1 |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
Investment in partnerships | (434 | ) | | (416 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other, net | 746 |
| | 78 |
| | 141 |
| | 71 |
| | 13 |
| | 193 |
| | 94 |
| | 14 |
| | 16 |
|
Deferred income tax liabilities (net) | $ | (10,469 | ) | | $ | (3,077 | ) | | $ | (3,456 | ) | | $ | (1,788 | ) | | $ | (1,240 | ) |
| $ | (2,058 | ) |
| $ | (1,061 | ) |
| $ | (600 | ) |
| $ | (489 | ) |
Unamortized investment tax credits | (732 | ) | | (705 | ) | | (13 | ) | | (1 | ) | | (4 | ) | | (8 | ) | | (2 | ) | | (3 | ) | | (4 | ) |
Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,201 | ) | | $ | (3,782 | ) | | $ | (3,469 | ) | | $ | (1,789 | ) | | $ | (1,244 | ) |
| $ | (2,066 | ) |
| $ | (1,063 | ) |
| $ | (603 | ) |
| $ | (493 | ) |
__________
(a) Includes remeasurement impacts related to the TCJA. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2018 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Plant basis differences | $ | (12,533 | ) | | $ | (2,495 | ) | | $ | (4,059 | ) | | $ | (1,862 | ) | | $ | (1,399 | ) | | $ | (2,577 | ) | | $ | (1,148 | ) | | $ | (743 | ) | | $ | (645 | ) |
Accrual based contracts | 117 |
| | (44 | ) | | — |
| | — |
| | — |
| | 161 |
| | — |
| | — |
| | — |
|
Derivatives and other financial instruments | 89 |
| | 35 |
| | 69 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Deferred pension and postretirement obligation | 1,435 |
| | (188 | ) | | (255 | ) | | (26 | ) | | (26 | ) | | (102 | ) | | (78 | ) | | (46 | ) | | (14 | ) |
Nuclear decommissioning activities | (351 | ) | | (351 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deferred debt refinancing costs | 234 |
| | 23 |
| | (7 | ) | | — |
| | (3 | ) | | 187 |
| | (4 | ) | | (2 | ) | | (1 | ) |
Regulatory assets and liabilities | (749 | ) | | — |
| | 300 |
| | (129 | ) | | 172 |
| | (90 | ) | | 58 |
| | 96 |
| | 83 |
|
Tax loss carryforward | 237 |
| | 78 |
| | — |
| | 18 |
| | 25 |
| | 96 |
| | 12 |
| | 52 |
| | 26 |
|
Tax credit carryforward | 811 |
| | 816 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Investment in partnerships | (797 | ) | | (775 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other, net | 934 |
| | 239 |
| | 151 |
| | 67 |
| | 12 |
| | 196 |
| | 98 |
| | 17 |
| | 19 |
|
Deferred income tax liabilities (net) | $ | (10,573 | ) | | $ | (2,662 | ) | | $ | (3,801 | ) | | $ | (1,932 | ) | | $ | (1,219 | ) |
| $ | (2,126 | ) |
| $ | (1,062 | ) |
| $ | (626 | ) |
| $ | (532 | ) |
Unamortized investment tax credits | (724 | ) | | (700 | ) | | (12 | ) | | (1 | ) | | (3 | ) | | (8 | ) | | (2 | ) | | (2 | ) | | (3 | ) |
Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (11,297 | ) | | $ | (3,362 | ) | | $ | (3,813 | ) | | $ | (1,933 | ) | | $ | (1,222 | ) |
| $ | (2,134 | ) |
| $ | (1,064 | ) |
| $ | (628 | ) |
| $ | (535 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | As of December 31, 2016 | As of December 31, 2017 (a) |
| | | | | | | | | | | Successor | | | | | | | | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Plant basis differences | $ | (17,966 | ) | | $ | (4,192 | ) | | $ | (5,034 | ) | | $ | (3,095 | ) | | $ | (1,977 | ) | | $ | (3,586 | ) | | $ | (1,678 | ) | | $ | (973 | ) | | $ | (869 | ) | $ | (12,490 | ) | | $ | (2,819 | ) | | $ | (3,825 | ) | | $ | (1,762 | ) | | $ | (1,368 | ) | | $ | (2,521 | ) | | $ | (1,152 | ) | | $ | (717 | ) | | $ | (607 | ) |
Accrual based contracts | 434 |
| | (115 | ) | | — |
| | — |
| | — |
| | 548 |
| | — |
| | — |
| | — |
| 150 |
| | (66 | ) | | — |
| | — |
| | — |
| | 216 |
| | — |
| | — |
| | — |
|
Derivatives and other financial instruments | (179 | ) | | (162 | ) | | (3 | ) | | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
| (85 | ) | | (66 | ) | | (2 | ) | | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Deferred pension and postretirement obligation | 2,287 |
| | (316 | ) | | (453 | ) | | (18 | ) | | (43 | ) | | (111 | ) | | (122 | ) | | (74 | ) | | (21 | ) | 1,463 |
| | (205 | ) | | (285 | ) | | (15 | ) | | (29 | ) | | (130 | ) | | (78 | ) | | (51 | ) | | (18 | ) |
Nuclear decommissioning activities | (509 | ) | | (509 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (553 | ) | | (553 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deferred debt refinancing costs | 325 |
| | 44 |
| | (13 | ) | | (1 | ) | | (3 | ) | | 293 |
| | (7 | ) | | (4 | ) | | (2 | ) | 217 |
| | 26 |
| | (8 | ) | | (1 | ) | | (3 | ) | | 203 |
| | (4 | ) | | (2 | ) | | (1 | ) |
Regulatory assets and liabilities | (3,319 | ) | | — |
| | (226 | ) | | 10 |
| | (240 | ) | | (1,205 | ) | | (194 | ) | | (75 | ) | | (69 | ) | (688 | ) | | — |
| | 489 |
| | (90 | ) | | 136 |
| | (184 | ) | | 39 |
| | 88 |
| | 86 |
|
Tax loss carryforward | 189 |
| | 61 |
| | 29 |
| | — |
| | 22 |
| | 77 |
| | 27 |
| | 39 |
| | 14 |
| 344 |
| | 76 |
| | 33 |
| | 9 |
| | 11 |
| | 156 |
| | 40 |
| | 68 |
| | 35 |
|
Tax credit carryforward | 446 |
| | 493 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 861 |
| | 868 |
| | 1 |
| | — |
| | — |
| | 6 |
| | — |
| | — |
| | — |
|
Investment in partnerships | (650 | ) | | (650 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (434 | ) | | (416 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other, net | 1,485 |
| | 403 |
| | 351 |
| | 99 |
| | 27 |
| | 225 |
| | 66 |
| | 34 |
| | 34 |
| 746 |
| | 78 |
| | 141 |
| | 71 |
| | 13 |
| | 193 |
| | 94 |
| | 14 |
| | 16 |
|
Deferred income tax liabilities (net) | $ | (17,457 | ) | | $ | (4,943 | ) | | $ | (5,349 | ) | | $ | (3,005 | ) | | $ | (2,214 | ) |
| $ | (3,760 | ) |
| $ | (1,908 | ) |
| $ | (1,053 | ) |
| $ | (913 | ) | $ | (10,469 | ) | | $ | (3,077 | ) | | $ | (3,456 | ) | | $ | (1,788 | ) | | $ | (1,240 | ) |
| $ | (2,058 | ) |
| $ | (1,061 | ) |
| $ | (600 | ) |
| $ | (489 | ) |
Unamortized investment tax credits | (658 | ) | | (626 | ) | | (15 | ) | | (1 | ) | | (5 | ) | | (9 | ) | | (2 | ) | | (3 | ) | | (4 | ) | (732 | ) | | (705 | ) | | (13 | ) | | (1 | ) | | (4 | ) | | (8 | ) | | (2 | ) | | (3 | ) | | (4 | ) |
Total deferred income tax liabilities (net) and unamortized investment tax credits | $ | (18,115 | ) | | $ | (5,569 | ) | | $ | (5,364 | ) | | $ | (3,006 | ) | | $ | (2,219 | ) |
| $ | (3,769 | ) |
| $ | (1,910 | ) |
| $ | (1,056 | ) |
| $ | (917 | ) | $ | (11,201 | ) | | $ | (3,782 | ) | | $ | (3,469 | ) | | $ | (1,789 | ) | | $ | (1,244 | ) |
| $ | (2,066 | ) |
| $ | (1,063 | ) |
| $ | (603 | ) |
| $ | (493 | ) |
__________
| |
(a) | Includes remeasurement impacts related to the TCJA. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2017:2018:
| | | | | | | | | | | | | Successor | | | | | | | | | | | | | | | | | | Successor | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
Federal | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Federal net operating loss | $ | 624 |
| (a)
| $ | — |
| | $ | 156 |
| | $ | 7 |
| | $ | — |
| | $ | 261 |
| | $ | 82 |
| | $ | 81 |
| | $ | 63 |
| | |
Deferred taxes on Federal net operating loss | 131 |
| | — |
| | 33 |
| | 1 |
| | — |
| | 55 |
| | 17 |
| | 17 |
| | 13 |
| | |
Federal general business credits carryforwards | 861 |
| (b) | 868 |
|
| 1 |
| | — |
|
| 1 |
| | 5 |
| | — |
| | — |
| | — |
| | 811 |
| (a) | 816 |
|
| — |
| | — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| |
State | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
State net operating losses | 3,555 |
| (c) | 1,479 |
| (c) | — |
| | 98 |
| (e) | 177 |
| (d) | 1,440 |
| (f) | 347 |
| (g) | 753 |
| (h) | 299 |
| (i) | 4,103 |
| (b) | 1,544 |
| (b) | — |
| | 224 |
| (c) | 395 |
| (d) | 1,492 |
| (e) | 192 |
| (f) | 772 |
| (g) | 365 |
| (h) |
Deferred taxes on state tax attributes (net) | 233 |
| | 97 |
| | — |
| | 8 |
| | 12 |
| | 98 |
| | 23 |
| | 51 |
| | 21 |
| | 272 |
| | 104 |
| | — |
| | 18 |
| | 26 |
| | 102 |
| | 12 |
| | 52 |
| | 26 |
| |
Valuation allowance on state tax attributes | 29 |
| | 23 |
| | — |
| | — |
| | 1 |
| | 5 |
| | — |
| | — |
| | — |
| | 35 |
| | 26 |
| | — |
| | — |
| | 1 |
| | 6 |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Exelon's federal net operating loss will begin expiring in 2034. |
| |
(b) | Exelon’s federal general business credit carryforwards will begin expiring in 2033. |
| |
(c)(b) | Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2018.2019. |
| |
(c) | PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031. |
| |
(d) | BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026. |
| |
(e) | PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031. |
| |
(f) | PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036. |
| |
(g)(f) | Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028.2033. |
| |
(h)(g) | DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2027.2030. |
| |
(i)(h) | ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031. |
Tabular Reconciliation of Unrecognized Tax Benefits
The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2018, 2017 2016 and 2015:2016:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unrecognized tax benefits at January 1, 2017 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
| | $ | 172 |
| | $ | 80 |
| | $ | 37 |
| | $ | 22 |
|
Increases based on tax positions related to 2017 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decreases based on tax positions related to 2017 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Change to positions that only affect timing | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Increases based on tax positions prior to 2017 | 28 |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Decreases based on tax positions prior to 2017 | (196 | ) | | (17 | ) | | — |
| | — |
| | — |
| | (61 | ) | | (21 | ) | | (16 | ) | | (22 | ) |
Decrease from settlements with taxing authorities | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decreases from expiration of statute of limitations | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Unrecognized tax benefits at December 31, 2017 | $ | 743 |
| | $ | 468 |
| | $ | 2 |
| | $ | — |
| | $ | 120 |
|
| $ | 125 |
|
| $ | 59 |
|
| $ | 21 |
|
| $ | 14 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unrecognized tax benefits at January 1, 2018 | $ | 743 |
| | $ | 468 |
| | $ | 2 |
| | $ | — |
| | $ | 120 |
| | $ | 125 |
| | $ | 59 |
| | $ | 21 |
| | $ | 14 |
|
Change to positions that only affect timing | 15 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Increases based on tax positions prior to 2018 | 30 |
| | 21 |
| | — |
| | — |
| | — |
| | 8 |
| | 7 |
| | 1 |
| | — |
|
Decreases based on tax positions prior to 2018 | (251 | ) | | (36 | ) | | — |
| | — |
| | (120 | ) | | (88 | ) | | (66 | ) | | (22 | ) | | — |
|
Decrease from settlements with taxing authorities | (53 | ) | | (53 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decreases from expiration of statute of limitations | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Unrecognized tax benefits at December 31, 2018 | $ | 477 |
| | $ | 408 |
| | $ | 2 |
| | $ | — |
| | $ | — |
|
| $ | 45 |
|
| $ | — |
|
| $ | — |
|
| $ | 14 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unrecognized tax benefits at January 1, 2017 | $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
| | $ | 172 |
| | $ | 80 |
| | $ | 37 |
| | $ | 22 |
|
Increases based on tax positions prior to 2017 | 28 |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
| | — |
| | — |
| | 14 |
|
Decreases based on tax positions prior to 2017 | (196 | ) | | (17 | ) | | — |
| | — |
| | — |
| | (61 | ) | | (21 | ) | | (16 | ) | | (22 | ) |
Decrease from settlements with taxing authorities | (5 | ) | | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Unrecognized tax benefits at December 31, 2017 | $ | 743 |
|
| $ | 468 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 120 |
|
| $ | 125 |
|
| $ | 59 |
|
| $ | 21 |
|
| $ | 14 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | | Successor | | | | | |
| | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unrecognized tax benefits at January 1, 2016 | $ | 1,078 |
| | $ | 534 |
| | $ | 142 |
| | $ | — |
| | $ | 120 |
| | $ | 22 |
| | $ | 8 |
| | $ | 3 |
| | $ | — |
| $ | 1,078 |
| | $ | 534 |
| | $ | 142 |
| | $ | — |
| | $ | 120 |
| | $ | 22 |
| | $ | 8 |
| | $ | 3 |
| | $ | — |
|
Merger balance transfer | 22 |
| | 5 |
| | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | — |
| 22 |
| | 5 |
| | — |
| | — |
| | — |
| | (5 | ) | | — |
| | — |
| | — |
|
Increases based on tax positions related to 2016 | 108 |
| | 10 |
| | — |
| | — |
| | — |
| | 59 |
| | 21 |
| | 16 |
| | 22 |
| 108 |
| | 10 |
| | — |
| | — |
| | — |
| | 59 |
| | 21 |
| | 16 |
| | 22 |
|
Decreases based on tax positions related to 2016 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Change to positions that only affect timing | (332 | ) | | (12 | ) | | (154 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (332 | ) | | (12 | ) | | (154 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Increases based on tax positions prior to 2016 | 88 |
| | — |
| | — |
| | — |
| | — |
| | 96 |
| | 51 |
| | 18 |
| | — |
| 88 |
| | — |
| | — |
| | — |
| | — |
| | 96 |
| | 51 |
| | 18 |
| | — |
|
Decreases based on tax positions prior to 2016 | (21 | ) | | (20 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (21 | ) | | (20 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decrease from settlements with taxing authorities | (27 | ) | | (27 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Decreases from expiration of statute of limitations | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Decreases from settlements with taxing authorities | | (27 | ) | | (27 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Unrecognized tax benefits at December 31, 2016 | $ | 916 |
|
| $ | 490 |
|
| $ | (12 | ) |
| $ | — |
|
| $ | 120 |
|
| $ | 172 |
|
| $ | 80 |
|
| $ | 37 |
|
| $ | 22 |
| $ | 916 |
| | $ | 490 |
| | $ | (12 | ) | | $ | — |
| | $ | 120 |
|
| $ | 172 |
|
| $ | 80 |
|
| $ | 37 |
|
| $ | 22 |
|
As a result of a court decision issued in July 2018 to an unrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax benefits increased in the third quarter of 2018 by approximately $71 million. Approximately $20 million of this increase impacted Exelon's and Generation’s effective tax rate and resulted in a charge to earnings in the third quarter of 2018. Exelon’s and Generation’s unrecognized federal and state tax benefits decreased in the fourth quarter of 2018 by approximately $90 million due to the settlement of a federal audit issue with IRS Appeals. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $9 million. |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Predecessor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unrecognized tax benefits at January 1, 2015 | $ | 1,829 |
| | $ | 1,357 |
| | $ | 149 |
| | $ | 44 |
| | $ | — |
| | $ | 702 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Increases based on tax positions related to 2015 | 108 |
| | — |
| | — |
| | — |
| | 106 |
| | — |
| | — |
| | — |
| | — |
|
Decreases based on tax positions related to 2015 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Change to positions that only affect timing | (705 | ) | | (659 | ) | | (7 | ) | | (44 | ) | | — |
| | (688 | ) | | — |
| | — |
| | — |
|
Increases based on tax positions prior to 2015 | 79 |
| | 65 |
| | — |
| | — |
| | 14 |
| | 11 |
| | 8 |
| | 3 |
| | — |
|
Decreases based on tax positions prior to 2015 | (116 | ) | | (112 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decreases from settlements with taxing authorities | (31 | ) | | (31 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Decreases from expiration of statute of limitations | (86 | ) | | (86 | ) | | — |
| | — |
| | — |
| | (3 | ) | | — |
| | — |
| | — |
|
Unrecognized tax benefits at December 31, 2015 | $ | 1,078 |
| | $ | 534 |
| | $ | 142 |
| | $ | — |
| | $ | 120 |
|
| $ | 22 |
|
| $ | 8 |
|
| $ | 3 |
|
| $ | — |
|
In the fourth quarter of 2018, Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits by $241 million, $33 million, $120 million, $88 million, $66 million, and $22 million, respectively, due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $26 million. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon’sExelon's return, the IRS National Office issued guidance concurring with Exelon’sExelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, in the first quarter of 2017 resulting in a benefit to Income taxes on Exelon’s, Generation’s, PHI’s, Pepco’s, DPL’sExelon's, Generation's, PHI's, Pepco's, DPL's, and ACE’sACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017. Please see the Other Income Tax Matters section below for additional details related to the like-kind exchange adjustments made in the second quarter of 2017.
Exelon and Generation have $7 million of unrecognized tax benefits at December 31, 2017 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon, Generation, and ComEd had $83 million, $7 million, and $(12) million of unrecognized tax benefits at December 31, 2016 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
Exelon, Generation, and ComEd had $415 million, $20 million and $142 million of unrecognized tax benefits at December 31, 2015 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.
Unrecognized tax benefits that if recognized would affect the effective tax rate
Exelon, Generation, ComEd and PHI have $463 million, $408 million, $2 million and $31 million, respectively, of unrecognized tax benefits at December 31, 2018 that, if recognized, would decrease the effective tax rate. PHI has $21 million of unrecognized state tax benefits at December 31, 2018 that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances. PHI and ACE have $14 million of unrecognized tax benefits at December 31, 2018 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Exelon, Generation, ComEd and PHI had $523 million,, $461 $461 million, $2 million and $32 million, respectively, of unrecognized tax benefits at December 31, 2017 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, DPL, and ACE have $120 million, $94 million, $59 million, $21 million and $14 million of unrecognized tax benefits at December 31, 2017 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon, Generation, PHI, Pepco, DPL, and ACE had $633 million,, $483 $483 million, $93 million, $21 million, $16 million, and $22 million, respectively, of unrecognized tax benefits at December 31, 2016 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco and DPL had $120 million, $80 million, $59 million, and $21 million of unrecognized tax benefits at December 31, 2016 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Exelon, Generation, and PHI had $538 million, $509 million, and $11 million, respectively, of unrecognizedUnrecognized tax benefits at December 31, 2015 that if recognized would decreaseaffect only the effectivetiming of tax rate. BGE, PHI, Pepcopayments
There are no unrecognized tax benefits as of December 31, 2018 that affect only the timing of tax payments.
Exelon and DPLGeneration had $120 million, $11 million, $8 million and $3$7 million of unrecognized tax benefits at December 31, 2015 that, if recognized, may be included in future base rates2017 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
Exelon, Generation and that portionComEd had $83 million, $7 million and $(12) million of unrecognized tax benefits at December 31, 2016 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
The disallowance of such positions would have no impact tonot materially affect the annual effective tax rate.rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of December 31, 2017,2018, Exelon and ComEd have approximately $39$33 million and $2 million, respectively, of unrecognized federal and state income tax benefits that could significantly decrease within the 12 months after the reporting date duerelated to a final resolution of the like-kind exchange litigation described further below. The recognitionIf Exelon does not appeal the October 2018 U.S. Court of theseAppeals for the Seventh Circuit's decision to the U.S. Supreme Court, Exelon's and ComEd's unrecognized tax benefits wouldwill decrease Exelon and ComEd's effective tax rate.in the first quarter of 2019. See below for further details.
Settlement of Income Tax Audits, Refund Claims, and Litigation
As of December 31, 2017,2018, Exelon, Generation, BGE, PHI Pepco, DPL, and ACE have approximately $683$425 million, $469$411 million, $120$14 million, $94 million, $59 million, $21 million,and $14 million respectively, of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $462$411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to BGE, Pepco, DPLPHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Total amounts of interest and penalties recognized
The following tables represent the net interest and penalties receivable (payable), including interest and penalties related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.
| | | | | | | | | | | | | Successor | | | | | | | | | | | | | | | | | | | | | | | | | |
Net interest receivable (payable) as of | Exelon(a) | | Generation | | ComEd(a) | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2018 | | $ | 236 |
| | $ | (2 | ) | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
December 31, 2017 | $ | 233 |
| | $ | (3 | ) | | $ | 4 |
| | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| 233 |
| | (3 | ) | | 4 |
| | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
|
December 31, 2016 | (507 | ) | | 46 |
| | (384 | ) | | 8 |
| | (1 | ) | | 2 |
| | 1 |
| | — |
| | 1 |
| |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
Net penalties receivable (payable) as of | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2017 | $ | (17 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
December 31, 2016 | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net penalties payable as of | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
December 31, 2018 | $ | (17 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
December 31, 2017 | (17 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
__________
| |
(a) | Change in balance attributable to Like-Kind Exchange interest payments, see Other Tax Matters for further discussion. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables set forth the net interest and penalty expense, including interest and penalties related to tax positions, recognized in Interest expense, net and Other, net in Other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
| | Net interest expense (income) for the years ended | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
December 31, 2018 | | $ | (3 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
December 31, 2017 | $ | 37 |
| | $ | (1 | ) | | $ | 11 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| 37 |
| | (1 | ) | | 11 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
December 31, 2016 | 165 |
| | (13 | ) | | 117 |
| | — |
| | — |
| | 6 |
| | — |
| | (1 | ) | 165 |
| | (13 | ) | | 117 |
| | — |
| | — |
| | 6 |
| | — |
| | (1 | ) |
December 31, 2015 | (13 | ) | | (31 | ) | | 7 |
| | — |
| | — |
| | (4 | ) | | — |
| | — |
| |
| | Net penalty expense (income) for the years ended | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
December 31, 2018 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
December 31, 2017 | $ | (2 | ) | | $ | — |
| | $ | — |
| $ | — |
| $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
December 31, 2016 | 106 |
| | — |
| | 86 |
| | — |
| | — |
| | — |
| | — |
| | — |
| 106 |
| | — |
| | 86 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
December 31, 2015 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | December 31, 2015 |
Net interest expense (income) | $ | — |
| | $ | (2 | ) | | | $ | — |
| | $ | (34 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | |
| Successor | | | Predecessor |
PHI | December 31, 2018 | | December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Net interest expense | $ | — |
| | $ | — |
| | $ | (2 | ) | | | $ | — |
|
Description of tax years open to assessment by major jurisdiction
|
| |
Taxpayer | Open Years |
Exelon (and predecessors) and subsidiaries consolidated Federalfederal income tax returns | 1999, 2001-20162001-2017 |
PHI Holdings and subsidiaries consolidated Federalfederal income tax returns | 2013-20162013, 2015-2016 |
Exelon and subsidiaries Illinois unitary income tax returns | 2013-2016 |
Constellation Illinois unitary income tax returns | 2011-March 20122010-2017 |
Constellation combined New York corporate income tax returns | 2010-March 2012 |
Exelon combined New York corporate income tax returns
| 2011-20162011-2017 |
Exelon New Jersey corporate income tax returns | 2013-20152013-2017 |
Various separate company (excluding PECO)Exelon Pennsylvania corporate net income tax returns | 2011-20162011-2017
|
PECO Pennsylvania separate company returns | 2010-20162015-2017
|
DPL Delaware separate company returns | Same as Federalfederal |
ACE New Jersey separate company returns | 2013-20162014-2017 |
Exelon and subsidiaries District of Columbia corporate income tax returns | 2014-2016 2015-2017 |
PHI Holdings and subsidiaries District of Columbia corporate income tax returns | 2014-20162015-2016
|
Various separate company Maryland corporate net income tax returns | Same as Federalfederal |
Other Tax Matters
Like-Kind Exchange
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain 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.
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 (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.
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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
electric generation facilities which were properly leased back to the municipalities. As previously disclosed, Exelon terminated its investment in one of the leases in 2014 and the remaining two leases were terminated in 2016.
The IRS asserted penalty. In June of 2017,that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which is a listed transaction that the IRS finalized its computationhas identified as a potentially abusive tax shelter. Thus, they disagreed with Exelon's position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon and Exelon filed a petition to initiate litigation in the United States Tax Court. In 2016, the Tax Court held that Exelon was not entitled to defer gain on the transaction. In addition to the tax and interest related to the gain deferral, the Tax Court also ruled that Exelon was liable for $90 million in penalties and interest owed byon the penalties. Exelon pursuant tohas fully paid the amounts assessed resulting from the Tax Court’sCourt decision.
In September of 2017, Exelon appealed thisthe Tax Court decision to the U.S. Court of Appeals for the Seventh Circuit.
In October 2018, the first quarterU.S. Court of 2013, Exelon concluded that it was no longer more likely than not thatAppeals for 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. Exelon agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest and penalty amounts.
Prior toSeventh Circuit affirmed the Tax Court’s decision, however,decision. Exelon did not believe it was likelyfiled a penalty would be assessed based on applicable case law and the factspetition seeking rehearing of the transaction. As a result, no charge had been recorded forSeventh Circuit’s decision, but the penalty or for after-tax interest on the penalty. While it has strong arguments on appeal with respect to both the merits and the penalty,Seventh Circuit denied that petition in December 2018. Exelon has determined that, pursuantuntil March 5, 2019 to seek a further review by the applicable authoritative guidance, it is no longer more likely than not to avoid ultimate impositionU.S. Supreme Court.
State Income Tax Law Changes
On April 24, 2018, Maryland enacted companion bills, House Bill 1794 and Senate Bill 1090, providing for a phase in of the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-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 equitysingle sales factor apportionment formula from the like-kind exchange position, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016,current three factor formula for determining an additional $150 million receivable and non-cash equity contributions from Exelon.
As a result of the IRS’s finalization of its computationentity's Maryland state income taxes. The single sales factor will be fully phased in the second quarter of 2017, Exelon recorded a benefit to earnings of approximately $26 million, consisting of an income tax benefit of $50 million and a reduction of penalties of $2 million, partially offset by after-tax interest expense of $26 million, while ComEd recorded a charge to earnings of approximately $23 million, consisting of income tax expense of $15 million and after-tax interest expense of $8 million.2022.
In the second quarter of 2017,2018, Exelon, amended its agreement with ComEdGeneration, PHI, Pepco and DPL recorded a one-time increase to also hold ComEd harmless fordeferred income taxes of approximately $16 million, $5 million, $17 million, $16 million and $1 million, respectively. At PHI, Pepco and DPL, the unfavorable impacts on its equity fromincrease to the additionalMaryland deferred income tax amounts owedliability was offset by ComEd as a result ofregulatory assets. Further, the IRS’s finalization of its computation related to the like-kind exchange position. Accordingly, in the second quarter of 2017, ComEd recorded an additional receivable and non-cash equity contribution from Exelon for the total $23 million. As of June 30, 2017, ComEd had a total receivable from Exelon pursuant to the hold harmless agreement of $369 million, which was included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet.
In the fourth quarter of 2017, the IRS assessed the tax, penalties and interest of approximately $1.3 billion related to the like-kind exchange, including $300 million attributable to ComEd. While Exelon will receive a tax benefit of approximately $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 net cash outflow for the like-kind exchange is 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 on ComEd’s equity from the like-kind exchange position. Following a final appellate decision, which is expected in 2018, Exelon expects to receive approximately $60 million related to final interest computations.
Of the above amounts payable, Exelon deposited with the IRS $1.25 billion in October of 2016. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. As a result of the IRS’s assessment of the tax, penalties and interest in the fourth quarter of 2017, the deposit is no longer available to Exelon and thus was reclassified from a current asset and is now reflected as an offset to the related liabilities for the tax, penalties, and interest that are included on
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s balance sheet as current liabilities. The remaining amount due of approximately $20 million was paid in the fourth quarter of 2017. The $300 million payable discussed above attributable to ComEd, net of ComEd’s receivable pursuant to the hold harmless agreement, was settled with Exelon in the third quarter of 2017. No recovery will be sought from ComEd customers for any interest, penalty, or additional income tax payment amounts resulting from 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. In the first quarter of 2016, Exelon terminated its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.
Long-Term State Tax Apportionment (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 changeschange in tax law and/is not expected to have a material ongoing impact to Exelon's, Generation's, PHI's, Pepco's or significant operational changes. Exelon's, PHI's and Pepco's long-term marginal state income tax rate were revised in the first quarterDPL's future results of 2017 as a result of a statutory rate change in Washington, D.C. As a result, Exelon,operations.
Long-Term Marginal State Income Tax Rate (Exelon, Generation, PHI and Pepco recorded a one-time decrease to Deferred income tax liability of $28 million, $8 million and $8 million, respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, Exelon, PHI and Pepco recorded a corresponding regulatory liability of $8 million, in the Consolidated Balance Sheets. In addition, Exelon recorded a decrease to Income tax expense of $20 million, net of federal taxes, in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2017.Pepco)
In the third quarter of 2017,2018, Exelon reviewed and updated its marginal state income tax rates based on 20162017 state apportionment rates. In addition, Exelon, Generation and ComEd recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.5% effective July 1, 2017. As a result of the rate changes, in the third quarter of 2017,2018, Exelon, Generation, PHI and ComEdDPL recorded a one-time decrease to deferred income taxes of approximately $50 million, $53 million, $4 million and $2 million respectively. Pepco recorded a one-time increase to Deferreddeferred income taxes of approximately $250$1 million. Exelon, PHI and DPL recorded a corresponding regulatory liability of approximately $1 million, $20$1 million and $270$2 million respectively, on their Consolidated Balance Sheets. Because income taxes are recovered through customer rates, each of Exelon and ComEdrespectively. Pepco recorded a corresponding regulatory asset of $272approximately $1 million. Further, Exelon, Generation and PHI recorded a decrease to Incomeincome tax expense of approximately $20 million and Generation recorded an increase to Income tax expense of approximately $20 million (each net(net of federal taxes) in their Consolidated Statements of Operationsapproximately $50 million, $53 million and Comprehensive Income for the three and nine months ended September 30, 2017. The Illinois statutory rate increase is not expected to have a material ongoing impact to Exelon’s, Generation’s or ComEd’s future results of operations.$3 million.
Allocation of Tax Benefits (All Registrants)
Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2018, Generation, PECO, BGE, PHI and ComEd recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $155 million, $48 million, $26 million, $2 million and $1 million respectively. Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
During 2017, Generation, PECO, BGE, and PHI recorded an allocation of Federalfederal tax benefits from Exelon under the Tax Sharing Agreement of $102 million, $16 million, $10 million and $7 million respectively. ComEd, Pepco, DPL, and ACE did not record an allocation of Federalfederal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
During 2016, Generation, PECO and BGE recorded an allocation of Federalfederal tax benefits from Exelon under the Tax Sharing Agreement of $94 million, $18 million and $8 million respectively. ComEd did not record an allocation of Federalfederal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. PHI, Pepco,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL and ACE did not record an allocation of Federalfederal tax benefits from Exelon as they were not a part of Exelon's 2015 consolidated tax return.
During 2015, Generation, PECO and BGE recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $57 million, $16 million and $7 million respectively. ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
15. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The following table provides a rollforward of the nuclear decommissioning ARO reflected onin Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 20162017 to December 31, 2017:2018:
| | | Exelon and Generation | |
Nuclear decommissioning ARO at January 1, 2016 | $ | 8,246 |
| |
Nuclear decommissioning ARO at January 1, 2017 | | $ | 8,734 |
|
Accretion expense | 436 |
| 458 |
|
Net increase for changes in and timing of estimated future cash flows | 61 |
| |
Costs incurred related to decommissioning plants | (9 | ) | |
Nuclear decommissioning ARO at December 31, 2016 (a) | 8,734 |
| |
Accretion Expense | 458 |
| |
Acquisition of FitzPatrick | 444 |
| 444 |
|
Net increase for changes in and timing of estimated future cash flows | 34 |
| |
Net increase due to changes in, and timing of, estimated future cash flows | | 34 |
|
Costs incurred related to decommissioning plants | (8 | ) | (8 | ) |
Nuclear decommissioning ARO at December 31, 2017 (a) | $ | 9,662 |
| 9,662 |
|
Accretion expense | | 478 |
|
Net decrease due to changes in, and timing of, estimated future cash flows | | (77 | ) |
Costs incurred related to decommissioning plants | | (58 | ) |
Nuclear decommissioning ARO at December 31, 2018 (a) (b) | | $ | 10,005 |
|
__________
| |
(a) | Includes $13$22 million and $10$13 million as the current portion of the ARO at December 31, 20172018 and 2016,2017, respectively, which is included in Other current liabilities onin Exelon’s and Generation’s Consolidated Balance Sheets. |
| |
(b) | Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. |
During 2017, Generation’s total nuclear ARO increased by approximately $928The net $77 million primarily reflecting year-to-date accretion ofdecrease in the ARO liability due to the passage of time, the recording of the fair value of the ARO, including subsequent purchase accounting adjustments,during 2018 for the acquisition of FitzPatrick (see Note 4—Mergers, Acquisitions and Dispositions), the announced early retirement of TMI, and impacts of ARO updates completed during 2017 to reflect changes in the amounts and timing of estimated decommissioning cash flows.flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $203 million decrease primarily due to lower estimated costs for the construction of interim spent fuel storage at TMI and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. These adjustments also include a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by a $116 million increase for the impact of the early retirement and the announced pending sale of Oyster Creek and a $122 million increase for estimated cost escalation rates, primarily for labor, energy and waste burial costs. See Note 5 — Mergers, Acquisitions and Dispositions and Note 8—Early Plant Retirements for additional information regarding Oyster Creek.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The net $34 million increase in the ARO during 2017 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $178 million increase due to higher assumed probabilities of early retirement of Salem and a $138 million increase in TMI’s ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in theTMI's ARO liability for TMI incorporates the early shutdown date, increases in the probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on an updated decommissioning cost study. See Note 8—8—Early Nuclear Plant Retirements for
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
additional information regarding Salem and TMI. These increases in the ARO were partially offset by a $180 million decrease for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as net decreases resulting from updates to the cost studies of Clinton, Quad Cities and Dresden.
During 2016, Generation’s ARO increased by approximately $488 million, primarily reflecting year-to-date accretion of the ARO liability of approximately $436 million due to the passage of time and impacts of ARO updates completed during 2016 to reflect changes in amounts and timing of estimated decommissioning cash flows. The $61 million increase in the ARO during 2016 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include increases of $288 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2025 to 2030 as well as increases resulting from updates to the cost studies of Oyster Creek, Zion, Calvert Cliffs, Ginna and Nine Mile Point. These increases were partially offset by a decrease of $165 million resulting from changes to the decommissioning scenarios and their probabilities as well as reductions in estimated cost escalation rates, primarily for labor, energy and waste burial costs. Most of the increase to the ARO resulting from the June 2, 2016, announcement to early retire Clinton and Quad Cities was reversed pursuant to the December 7, 2016, enactment of the Illinois FEJA. See Note 8—Early Nuclear Plant Retirements for additional information.
Nuclear Decommissioning Trust Fund InvestmentsNDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment (NDCA) with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the currentpreviously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to nuclear decommissioning trustNDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 20172018 and 2016,2017, Exelon and Generation had NDT fund investmentsfunds totaling $12,695 millionand $13,349 million, respectively. Included within the December 31, 2018 balance is the $890 million reclassification of Oyster Creek NDT as Assets held for sale in Exelon's and $11,061 million, respectively. The increase is primarily driven by improved market performanceGeneration's Consolidated Balance Sheets. See Note 5 — Mergers, Acquisitions and the acquisition of FitzPatrick. ForDispositions for additional information related toregarding the announced pending sale of Oyster Creek. The NDT funds include $144 million and $77 million for the current portion of the NDT fund investments, referat December 31, 2018 and 2017, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Balance Sheets. See Note 11—Fair Value of Financial Assets and Liabilities.Liabilities for additional information related to the NDT funds.
The following table provides unrealized (losses) gains on NDT funds of Exelon and Generation for the years ended 2018, 2017 2016 and 2015:2016:
|
| | | | | | | | | | | |
| Exelon and Generation |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units (a) | $ | 455 |
| | $ | 216 |
| | $ | (282 | ) |
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units (b)(c) | 521 |
| | 194 |
| | (197 | ) |
|
| | | | | | | | | | | |
| 2018 | | 2017 | | 2016 |
Net unrealized (losses) gains on NDT funds—Regulatory Agreement Units (a) | $ | (715 | ) | | $ | 455 |
| | $ | 216 |
|
Net unrealized (losses) gains on NDT funds—Non-Regulatory Agreement Units (b) | (483 | ) | | 521 |
| | 194 |
|
__________
| |
(a) | Net unrealized (losses) gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities onin Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates onin Generation’s Consolidated Balance Sheets. |
| |
(b) | Excludes $(10) million, $(1) million and $7 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2017, 2016 and 2015, respectively. Net unrealized (losses) gains related to Zion Station pledged assets are included in the Other current liabilities and Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets in 2017 and 2016, respectively. |
| |
(c) | Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. |
InterestRealized earnings, including interest and dividends on the NDT fundfunds, for the non-Regulatory Agreement Units investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments forIncome whereas the Regulatory Agreement
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.net.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreementagreements with the ICC and PAPUC that dictatesdictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis as long as funds heldand the former PECO units in the NDT funds are expected to exceed the total, estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income as long as the NDT funds are expected to exceed the total estimated decommissioning obligation. For the former PECO units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at GenerationGeneration. ComEd and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd hasPECO have recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations and financial positionsstatements could be material. As of December 31, 2017,2018, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations and financial positionsstatements could be material.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Refer toSee Note 3—4—Regulatory Matters and Note 26—25—Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
On September 1,In 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the Zion Station’s assets, (other than land) associated with Zion Station, including assets held inthe related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF and decommission the SNF dry storage facility, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement, subject to certain restrictions, from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another company. Generation reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore,As 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 Pledgedas pledged assets for Zion Station decommissioning, which are recorded within Other current assets within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally,transaction, and the transferred ARO for decommissioning was replaced with a Payablepayable for Zion Station decommissioning, which is recorded in Generation’sOther current liabilities in Exelon’s and Exelon’sGeneration’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT fund assets, net of applicable taxes, will beare recorded as a change in the Payablepayable 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 $114$120 million, which is included within the nuclear decommissioning ARO at December 31, 2017.2018. 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 theExelon's and Generation's pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 20172018 and 2016:2017:
|
| | | | | | | |
| Exelon and Generation |
| 2017 | | 2016 |
Carrying value of Zion Station pledged assets (a) | $ | 39 |
| | $ | 113 |
|
Payable to Zion Solutions (b) | 37 |
| | 104 |
|
Current portion of payable to Zion Solutions (c) | 37 |
| | 90 |
|
Cumulative withdrawals by Zion Solutions to pay decommissioning costs (d) | 942 |
| | 878 |
|
__________ |
| | | | | | | |
| 2018 | | 2017 |
Carrying value of Zion Station pledged assets | $ | 9 |
| | $ | 39 |
|
Current payable to ZionSolutions (a) | 9 |
| | 37 |
|
Cumulative withdrawals by ZionSolutions to pay decommissioning costs (b) | 965 | | 942 |
_______
| |
(a) | Included in Other current assetsliabilities within Exelon’sExelon's and Generation’sGeneration's Consolidated Balance Sheets in 2017. |
| |
(b) | Sheets. Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activitygains and losses associated with the Zion Station NDT Funds.funds. The NDT Fundsfunds will be utilized to satisfy the tax obligations as gains and losses are realized. |
| |
(c) | Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets. |
| |
(d)(b) | Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings. |
ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility at Zion Station.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. In accordance with the terms of the ASA, the letter of credit was reduced to $98$45 millionin August 2017May 2018 due to the completion of key decommissioning milestones. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded onin Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 20172018 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2018 for Oyster Creek and 2019 for TMI); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 20172018 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under four possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 4.8%5.0% to 6.4%6.2% (as compared to a historical 5-year annual average pre-tax return of approximately 8%4.9%).
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on March 31,30, 2017 for all units except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above) and FitzPatrick which is still owned by Entergy as of the NRC reporting period. This status report demonstrated adequate decommissioning funding assurance for all units 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 under NuclearSee NDT Funds section above for additional information.
On March 28, 2018, Generation submitted its annual decommissioning funding status report with the NRC for shutdown reactors, reactors within five years of shutdown except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning Trust Fund Investments above,above), and reactor involved in an acquisition. This report reflected the amount collected from PECO ratepayers has been adjusted instatus of decommissioning funding assurance as of December 31, 2017 and included an update for the acquisition of FitzPatrick on March 31, 2017, filingthe early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced retirement date of Oyster Creek and the updated status of Peach Bottom Unit 1 based on the new collections rate described above. As of December 31, 2017, Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved in an acquisition.
Combined Notes to the PAPUC which was approved on August 8, 2017 and effective on January 1, 2018.Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation will file its next decommissioning funding status report for all units with the NRC by March 31, 2018 for shutdown reactors and reactors within five years of shutdown.2019. This report will reflect the status of decommissioning funding assurance as of December 31, 2017 and will include the early retirement of TMI announced on May 30, 2017, in addition to an adjustment for the February 2, 2018 announced retirement date for Oyster Creek.2018. A shortfall at any unit could necessitate that Exelon postGeneration address the shortfall by, among other things, obtaining a parental guarantee for Generation's share of the funding assurance. However, the amount of any required guarantee or other assurance will ultimately depend on the decommissioning approach, adopted, the associated level of costs, and the decommissioning trust fund investment performance going forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. PHI and theThe Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1—Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a rollforward of the non-nuclear AROs reflected onin the Registrants’ Consolidated Balance Sheets from January 1, 20162017 to December 31, 2017:2018:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI(g) | | Pepco | | DPL | | ACE |
Non-nuclear AROs at January 1, 2016 | $ | 355 |
| | $ | 197 |
|
| $ | 113 |
|
| $ | 27 |
|
| $ | 18 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Merger with PHI(a) | 8 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Net increase due to changes in, and timing of, estimated future cash flows(b) | 34 |
| | 8 |
|
| 4 |
|
| 1 |
|
| 7 |
| | 14 |
| | 2 |
| | 9 |
| | 3 |
|
Development projects(c) | 11 |
| | 11 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Accretion expense(d) | 18 |
| | 10 |
| | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Sale of generating assets(e) | (22 | ) | | (22 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Payments | (11 | ) | | (6 | ) |
| (3 | ) |
| (1 | ) |
| (1 | ) | | — |
| | — |
| | — |
| | — |
|
Non-nuclear AROs at December 31, 2016(f) | 393 |
| | 199 |
|
| 121 |
|
| 28 |
|
| 24 |
| | 14 |
| | 2 |
|
| 9 |
|
| 3 |
|
Net increase (decrease) due to changes in, and timing of, estimated future cash flows(b) | (11 | ) | | (1 | ) |
| (13 | ) |
| (1 | ) |
| 2 |
| | 2 |
| | 1 |
| | 1 |
| | — |
|
Development projects(c) | 1 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Accretion expense(d) | 18 |
| | 10 |
|
| 7 |
|
| 1 |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Deconsolidation of EGTP(h) | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Payments | (10 | ) | | (5 | ) |
| (2 | ) |
| (1 | ) |
| (2 | ) | | — |
| | — |
| | — |
| | — |
|
Non-nuclear AROs at December 31, 2017(f) | $ | 384 |
| | $ | 197 |
|
| $ | 113 |
|
| $ | 27 |
|
| $ | 24 |
| | $ | 16 |
| | $ | 3 |
|
| $ | 10 |
|
| $ | 3 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | |
| Predecessor |
| PHI(g) |
| 2016 |
Non-nuclear AROs at January 1, 2016 | $ | 8 |
|
Accretion expense | — |
|
Non-nuclear AROs at March 23, 2016 | $ | 8 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Non-nuclear AROs at January 1, 2017 | $ | 393 |
| | $ | 199 |
|
| $ | 121 |
|
| $ | 28 |
|
| $ | 24 |
| | $ | 14 |
| | $ | 2 |
| | $ | 9 |
| | $ | 3 |
|
Net (decrease) increase due to changes in, and timing of, estimated future cash flows | (11 | ) | | (1 | ) |
| (13 | ) |
| (1 | ) |
| 2 |
| | 2 |
| | 1 |
| | 1 |
| | — |
|
Development projects | 1 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Accretion expense(a) | 18 |
| | 10 |
| | 7 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Deconsolidation of EGTP | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Payments | (10 | ) | | (5 | ) |
| (2 | ) |
| (1 | ) |
| (2 | ) | | — |
| | — |
| | — |
| | — |
|
Non-nuclear AROs at December 31, 2017 | 384 |
| | 197 |
|
| 113 |
|
| 27 |
|
| 24 |
| | 16 |
| | 3 |
|
| 10 |
|
| 3 |
|
Net increase due to changes in, and timing of, estimated future cash flows(b) | 80 |
| | 35 |
|
| 7 |
|
| — |
|
| 2 |
| | 36 |
| | 34 |
| | 1 |
| | 1 |
|
Accretion expense(a) | 16 |
| | 10 |
|
| 4 |
|
| 1 |
|
| 1 |
| | — |
| | — |
| | — |
| | — |
|
Asset divestitures | (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Payments | (6 | ) | | (1 | ) |
| (3 | ) |
| — |
|
| (2 | ) | | — |
| | — |
| | — |
| | — |
|
Non-nuclear AROs at December 31, 2018 | $ | 471 |
| | $ | 238 |
|
| $ | 121 |
|
| $ | 28 |
|
| $ | 25 |
| | $ | 52 |
| | $ | 37 |
|
| $ | 11 |
|
| $ | 4 |
|
__________
| |
(a) | Following the completion of the PHI merger on March 23, 2016, PHI's AROs related to its unregulated business interests were transferred to Exelon and Generation. |
| |
(b) | During the year ended December 31, 2017, ComEd recorded a decrease of $1 million in Operating and maintenance expense. Generation, PECO, BGE, Pepco, DPL and ACE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2017. During the year ended December 31, 2016, Generation recorded a increase of $1 million in Operating and maintenance expense. ComEd, PECO, BGE, Pepco, DPL and ACE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2016. |
| |
(c) | Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites. |
| |
(d) | For ComEd PECO and BGE,PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment. |
| |
(e)(b) | ReflectsIn 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a reduction towaterfront property in the ARO resulting primarily from the salesDistrict of the New Boston generating siteColumbia occupied by an active substation and Upstream businessformer Pepco operated steam plant building, which Pepco retired and closed in 2016. See Note 4—Mergers, Acquisitions and Dispositions for further information. |
| |
(f) | Excludes the current portion of the ARO at December 31, 2017 for Generation, ComEd and BGE of $1 million, $2 million and $2 million, respectively. Excludes the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE of $1 million, $2 million and $3 million, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets. |
| |
(g) | For PHI, the successor period includes activity for the year ended December 31, 2017 and the period of March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the period of January 1, 2016 through March 23, 2016. |
| |
(h) | See Note 4—Mergers, Acquisitions and Dispositions for additional information.1981. |
16. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all current employees. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
employees participate in cash balance pension plans. Effective February 1, 2018, most newly-hired Generation and BSC non-represented, non-craft, employees are not eligible for pension benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.
Effective March 23, 2016,January 1, 2019, Exelon becameis merging the sponsorExelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program (ECRP). The merging of allthe plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period 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 transferredthe merged ECRP rather than each individual plan.
Combined Notes to Exelon.Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2017:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2018:
|
| | | | | | | | | | | | | | | | | | |
| | Operating Company(e) |
Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | BSC | | PHI | | Pepco | | DPL | | ACE |
Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Retirement Program(a) | | X | | X | | X | | X | | X | | X | | X | | | | |
Exelon Corporation Cash Balance Pension Plan(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Pension Plan for Bargaining Unit Employees(a) | | X | | X | | | | | | X | | | | | | | | |
Exelon New England Union Employees Pension Plan(a) | | X | | | | | | | | | | | | | | | | |
Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek(a) | | X | | X | | X | | | | X | | | | | | | | |
Pension Plan of Constellation Energy Group, Inc.(b) | | X | | X | | X | | X | | X | | X | | | | X | | |
Pension Plan of Constellation Energy Nuclear Group, LLC(c) | | X | | X | | | | X | | X | | X | | | | | | |
Nine Mile Point Pension Plan(c) | | X | | | | | | | | X | | | | | | | | |
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B(b)
| | X | | | | | | | | | | | | | | | | |
Pepco Holdings LLC Retirement Plan(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
Non-Qualified Pension Plans: | | | | | | | | | | | | | | | | | | |
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan(a) | | X | | X | | X | | | | X | | X | | | | | | |
Exelon Corporation Supplemental Management Retirement Plan(a) | | X | | X | | X | | X | | X | | X | | | | | | |
Constellation Energy Group, Inc. Senior Executive Supplemental Plan(b) | | X | | | | | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Supplemental Pension Plan(b) | | X | | | | | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Benefits Restoration Plan(b) | | X | | X | | | | X | | X | | X | | | | | | |
Constellation Energy Nuclear Plan, LLC Executive Retirement Plan(c) | | X | | | | | | | | X | | | | | | | | |
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan(c) | | X | | | | | | | | X | | | | | | | | |
Baltimore Gas & Electric Company Executive Benefit Plan(b) | | X | | | | | | X | | X | | | | | | | | |
Baltimore Gas & Electric Company Manager Benefit Plan(b)
| | X | | X | | | | X | | X | | | | | | | | |
Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) | | X | | | | | | | | X | | X | | X | | X | | X |
Conectiv Supplemental Executive Retirement Plan (d)
| | X | | | | | | | | X | | X | | | | X | | X |
Pepco Holdings LLC Combined Executive Retirement Plan (d)
| | X | | | | | | | | | | X | | X | | X | | | | |
Atlantic City Electric Director Retirement Plan (d)
| | | | | | | | | | | | | | | | | | X |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | |
| | Operating Company(e) |
Name of Plan: | | Generation | | ComEd | | PECO | | BGE | | BSC | | PHI | | Pepco | | DPL | | ACE |
Other Postretirement Benefit Plans: | | | | | | | | | | | | | | | | | | |
PECO Energy Company Retiree Medical Plan(a) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
Exelon Corporation Health Care Program(a) | | X | | X | | X | | X | | X | | X | | X | | | | | | X |
Exelon Corporation Employees’ Life Insurance Plan(a) | | X | | X | | X | | X | | X | | | | | | | | |
Exelon Corporation Health Reimbursement Arrangement Plan(a) | | X | | X | | X | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Retiree Medical Plan(b) | | X | | X | | X | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Retiree Dental Plan(b) | | X | | | | | | X | | X | | | | | | | | |
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan(b) | | X | | X | | X | | X | | X | | | | | | | | |
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan(b) | | X | | | | | | | | | | | | | | | | |
Exelon New England Union Post-Employment Medical Savings Account Plan(a) | | X | | | | | | | | | | | | | | | | |
Retiree Medical Plan of Constellation Energy Nuclear Group LLC(c) | | X | | | | | | X | | X | | | | | | | | |
Retiree Dental Plan of Constellation Energy Nuclear Group LLC(c) | | X | | | | | | X | | X | | | | | | | | |
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees(c) | | X | | | | | | | | X | | | | | | | | |
Pepco Holdings LLC Welfare Plan for Retirees(d) | | X | | X | | X | | X | | X | | X | | X | | X | | X |
______________________
| |
(a) | These plans are collectively referred to as the legacy Exelon plans. |
| |
(b) | These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans. |
| |
(c) | These plans are collectively referred to as the legacy CENG plans. |
| |
(d) | These plans are collectively referred to as the legacy PHI plans. |
| |
(e) | Employees generally remain in their legacy benefit plans when transferring between operating companies. |
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets and Funded Status
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to AOCI and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.
During the first quarter of 2018, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2018. This valuation resulted in an increase to the pension and OPEB obligations of $23 million and $14 million, respectively. Additionally, accumulated other comprehensive loss decreased by $18 million (after-tax) and regulatory assets and liabilities increased by $61 million and $1 million, respectively.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
During the first quarter of 2017, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2017. This valuation resulted in an increase to the pension obligation of $92 million and an increase to the other postretirement benefit obligation of $57 million. Additionally, accumulated other comprehensive loss increased by approximately $59 million (after tax), regulatory assets increased by approximately $57 million and regulatory liabilities increased by approximately $4 million.
In connection with the acquisition of FitzPatrick in the first quarter of 2017, Exelon recorded pension and OPEB obligations for FitzPatrick employees of $16 million and $17 million, respectively. Refer toSee Note 45 — Mergers, Acquisitions and Dispositions for additional discussioninformation of the acquisition of FitzPatrick.
The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
Exelon | 2017 | | 2016(a) | | 2017 | | 2016(a) | 2018 | | 2017 | | 2018 | | 2017 |
Change in benefit obligation: | | | | | | | | | | | | | | |
Net benefit obligation at beginning of year | $ | 21,060 |
| | $ | 17,753 |
| | $ | 4,457 |
| | $ | 3,938 |
| $ | 22,337 |
| | $ | 21,060 |
| | $ | 4,856 |
| | $ | 4,457 |
|
Service cost | 387 |
| | 354 |
|
| 106 |
| | 107 |
| 405 |
| | 387 |
|
| 112 |
| | 106 |
|
Interest cost | 842 |
| | 830 |
|
| 182 |
| | 185 |
| 802 |
| | 842 |
|
| 175 |
| | 182 |
|
Plan participants’ contributions | — |
| | — |
| | 53 |
| | 54 |
| — |
| | — |
| | 45 |
| | 53 |
|
Actuarial loss (gain) | 1,182 |
| | 567 |
| | 350 |
| | (136 | ) | |
Actuarial (gain) loss(a) | | (1,561 | ) | | 1,182 |
| | (540 | ) | | 350 |
|
Plan amendments | 9 |
| | (60 | ) | | — |
| | — |
| (4 | ) | | 9 |
| | — |
| | — |
|
Acquisitions/divestitures(b) | 16 |
| | 2,667 |
| | 17 |
| | 589 |
| |
Acquisitions(b) | | — |
| | 16 |
| | — |
| | 17 |
|
Settlements | (34 | ) | | — |
|
| — |
| | — |
| (48 | ) | | (34 | ) |
| (4 | ) | | — |
|
Gross benefits paid | (1,125 | ) | | (1,051 | ) |
| (309 | ) | | (280 | ) | (1,239 | ) | | (1,125 | ) |
| (275 | ) | | (309 | ) |
Net benefit obligation at end of year | $ | 22,337 |
| | $ | 21,060 |
| | $ | 4,856 |
| | $ | 4,457 |
| $ | 20,692 |
| | $ | 22,337 |
| | $ | 4,369 |
| | $ | 4,856 |
|
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
Exelon | 2017 | | 2016(a) | | 2017 | | 2016(a) | 2018 | | 2017 | | 2018 | | 2017 |
Change in plan assets: | | | | | | | | | | | | | | |
Fair value of net plan assets at beginning of year | $ | 16,791 |
| | $ | 14,347 |
| | $ | 2,578 |
| | $ | 2,293 |
| $ | 18,573 |
| | $ | 16,791 |
| | $ | 2,732 |
| | $ | 2,578 |
|
Actual return on plan assets | 2,600 |
| | 1,061 |
| | 346 |
| | 128 |
| (945 | ) | | 2,600 |
| | (136 | ) | | 346 |
|
Employer contributions | 341 |
|
| 347 |
|
| 64 |
|
| 50 |
| 337 |
|
| 341 |
|
| 46 |
|
| 64 |
|
Plan participants’ contributions | — |
| | — |
| | 53 |
| | 54 |
| — |
| | — |
| | 45 |
| | 53 |
|
Gross benefits paid | (1,125 | ) |
| (1,051 | ) |
| (309 | ) |
| (280 | ) | (1,239 | ) |
| (1,125 | ) |
| (275 | ) |
| (309 | ) |
Acquisitions/divestitures(b) | — |
| | 2,087 |
| | — |
| | 333 |
| |
Settlements | (34 | ) |
| — |
|
| — |
|
| — |
| (48 | ) |
| (34 | ) |
| (4 | ) |
| — |
|
Fair value of net plan assets at end of year | $ | 18,573 |
| | $ | 16,791 |
| | $ | 2,732 |
| | $ | 2,578 |
| $ | 16,678 |
| | $ | 18,573 |
| | $ | 2,408 |
| | $ | 2,732 |
|
__________
| |
(a) | The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate. |
| |
(b) | Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017. |
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
|
| | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
Exelon | 2018 | | 2017 | | 2018 | | 2017 |
Other current liabilities | $ | 26 |
| | $ | 28 |
| | $ | 33 |
| | $ | 31 |
|
Pension obligations | 3,988 |
|
| 3,736 |
|
| — |
|
| — |
|
Non-pension postretirement benefit obligations | — |
| | — |
| | 1,928 |
|
| 2,093 |
|
Unfunded status (net benefit obligation less plan assets) | $ | 4,014 |
|
| $ | 3,764 |
|
| $ | 1,961 |
|
| $ | 2,124 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| Predecessor |
| Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Change in benefit obligation: | | | |
Net benefit obligation at beginning of the period | $ | 2,490 |
| | $ | 563 |
|
Service cost | 12 |
| | 1 |
|
Interest cost | 26 |
| | 6 |
|
Actuarial (gain) loss | (30 | ) | | (5 | ) |
Gross benefits paid | (2 | ) | | (1 | ) |
Net benefit obligation at end of the period | $ | 2,496 |
| | $ | 564 |
|
|
| | | | | | | |
| Predecessor |
| Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Change in plan assets: | | | |
Fair value of net plan assets at beginning of the period | $ | 2,018 |
| | $ | 348 |
|
Employer and plan participant contributions | 4 |
| | 1 |
|
Gross benefits paid by plan | (2 | ) | | (1 | ) |
Fair value of net plan assets at end of the period | $ | 2,020 |
| | $ | 348 |
|
__________
| |
(a) | 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016. |
| |
(b) | Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017. Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans. |
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
|
| | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
Exelon | 2017 | | 2016(a) | | 2017 | | 2016(a) |
Other current liabilities | $ | 28 |
| | $ | 21 |
| | $ | 31 |
| | $ | 31 |
|
Pension obligations | 3,736 |
|
| 4,248 |
|
| — |
|
| — |
|
Non-pension postretirement benefit obligations | — |
| | — |
| | 2,093 |
|
| 1,848 |
|
Unfunded status (net benefit obligation less plan assets) | $ | 3,764 |
|
| $ | 4,269 |
|
| $ | 2,124 |
|
| $ | 1,879 |
|
__________
| |
(a) | Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. |
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.
| | PBO in excess of plan assets | | | | Exelon |
| Exelon | 2018 | | 2017 |
| 2017 | | 2016 | |
Projected benefit obligation | $ | 22,337 |
| | $ | 21,060 |
| $ | 20,692 |
| | $ | 22,337 |
|
Fair value of net plan assets | 18,573 |
| | 16,791 |
| 16,678 |
| | 18,573 |
|
| | ABO in excess of plan assets | | | | Exelon |
| Exelon | 2018 | | 2017 |
| 2017 | | 2016 | |
Projected benefit obligation | $ | 22,337 |
| | $ | 21,060 |
| $ | 20,692 |
| | $ | 22,337 |
|
Accumulated benefit obligation | 21,153 |
| | 19,930 |
| 19,656 |
| | 21,153 |
|
Fair value of net plan assets | 18,573 |
| | 16,791 |
| 16,678 |
| | 18,573 |
|
On a PBO basis, the Exelon plans were funded at 83%81% and 80%83% at December 31, 20172018 and 2016,2017, respectively. On an ABO basis, the Exelon plans were funded at 88%85% and 84%88% at December 31, 20172018 and 2016,2017, respectively. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.
Components of Net Periodic Benefit Costs
The majority of the 20172018 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.04%3.62%. The majority of the 20172018 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.58%6.60% for funded plans and a discount rate of 4.04%3.61%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2018, 2017 2016 and 20152016 and PHI's net periodic benefit costs, prior to capitalization, for the predecessor period of January 1, 2016 to March 23, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
Exelon | 2017(a) | | 2016(b) | | 2015 | | 2017(a) | | 2016(b) | | 2015 | 2018 | | 2017(a) | | 2016(b) | | 2018 | | 2017(a) | | 2016(b) |
Components of net periodic benefit cost: | | | | | | | | | | | | | | | | | | | | | | |
Service cost | $ | 387 |
|
| $ | 354 |
|
| $ | 326 |
|
| $ | 106 |
|
| $ | 107 |
|
| $ | 119 |
| $ | 405 |
|
| $ | 387 |
|
| $ | 354 |
|
| $ | 112 |
|
| $ | 106 |
|
| $ | 107 |
|
Interest cost | 842 |
|
| 830 |
|
| 710 |
|
| 182 |
|
| 185 |
|
| 167 |
| 802 |
|
| 842 |
|
| 830 |
|
| 175 |
|
| 182 |
|
| 185 |
|
Expected return on assets | (1,196 | ) | | (1,141 | ) | | (1,026 | ) | | (162 | ) | | (162 | ) | | (151 | ) | (1,252 | ) | | (1,196 | ) | | (1,141 | ) | | (173 | ) | | (162 | ) | | (162 | ) |
Amortization of: | | | | | | | | | | | | | | | | | | | | | | |
Prior service cost (credit) | 1 |
| | 14 |
| | 13 |
| | (188 | ) | | (185 | ) | | (174 | ) | 2 |
| | 1 |
| | 14 |
| | (186 | ) | | (188 | ) | | (185 | ) |
Actuarial loss | 607 |
| | 554 |
| | 571 |
| | 61 |
| | 63 |
| | 80 |
| 629 |
| | 607 |
| | 554 |
| | 66 |
| | 61 |
| | 63 |
|
Settlement and other charges(c) | 3 |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
| 3 |
| | 3 |
| | 2 |
| | 1 |
| | — |
| | — |
|
Net periodic benefit cost | $ | 644 |
| | $ | 613 |
| | $ | 596 |
| | $ | (1 | ) | | $ | 8 |
| | $ | 41 |
| $ | 589 |
| | $ | 644 |
| | $ | 613 |
| | $ | (5 | ) | | $ | (1 | ) | | $ | 8 |
|
__________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | PHI net periodic benefit costs for the period prior to the merger are not included in the table above. |
| |
(c) | 2016 amount includes an additional termination benefit for PHI. |
|
| | | | | | | | | | | | | | | |
| Predecessor |
| Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
Components of net periodic benefit cost: | | | | | | | |
Service cost | $ | 12 |
| | $ | 57 |
| | $ | 1 |
| | $ | 7 |
|
Interest cost | 26 |
| | 109 |
| | 6 |
| | 24 |
|
Expected return on assets | (30 | ) | | (140 | ) | | (5 | ) | | (22 | ) |
Amortization of: | | | | | | | |
Prior service cost (credit) | — |
| | 2 |
| | (3 | ) | | (13 | ) |
Actuarial loss | 14 |
| | 65 |
| | 2 |
| | 8 |
|
Net periodic benefit cost | $ | 22 |
| | $ | 93 |
| | $ | 1 |
| | $ | 4 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
| Predecessor |
| Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Components of net periodic benefit cost: | | | |
Service cost | $ | 12 |
| | $ | 1 |
|
Interest cost | 26 |
| | 6 |
|
Expected return on assets | (30 | ) | | (5 | ) |
Amortization of: | | | |
Prior service cost (credit) | — |
| | (3 | ) |
Actuarial loss | 14 |
| | 2 |
|
Net periodic benefit cost | $ | 22 |
| | $ | 1 |
|
Components of AOCI and Regulatory Assets
Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2018, 2017 2016 and 20152016 for all plans combined and the components of PHI's predecessor AOCI and regulatory assets (liabilities) for the period January 1, 2016 to March 23, 2016.
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
Exelon | 2017 | | 2016(a) | | 2015 | | 2017 | | 2016(a) | | 2015 | 2018 | | 2017 | | 2016(a) | | 2018 | | 2017 | | 2016(a) |
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | | | | | | | | | | | | | |
Current year actuarial (gain) loss | $ | (222 | ) | | $ | 644 |
| | $ | 476 |
| | $ | 166 |
| | $ | (101 | ) | | $ | (194 | ) | $ | 635 |
| | $ | (222 | ) | | $ | 644 |
| | $ | (232 | ) | | $ | 166 |
| | $ | (101 | ) |
Amortization of actuarial loss | (607 | ) | | (554 | ) | | (571 | ) | | (61 | ) | | (63 | ) | | (80 | ) | (629 | ) | | (607 | ) | | (554 | ) | | (66 | ) | | (61 | ) | | (63 | ) |
Current year prior service cost (credit) | 9 |
| | (60 | ) | | — |
| | — |
| | — |
| | (23 | ) | (4 | ) | | 9 |
| | (60 | ) | | — |
| | — |
| | — |
|
Amortization of prior service (cost) credit | (1 | ) | | (14 | ) | | (13 | ) | | 188 |
| | 185 |
| | 174 |
| (2 | ) | | (1 | ) | | (14 | ) | | 186 |
| | 188 |
| | 185 |
|
Settlements | (3 | ) | | — |
| | (2 | ) | | — |
| | — |
| | — |
| (3 | ) | | (3 | ) | | — |
| | — |
| | — |
| | — |
|
Acquisitions | — |
| | 994 |
| | — |
| | — |
| | 94 |
| | — |
| — |
| | — |
| | 994 |
| | — |
| | — |
| | 94 |
|
Total recognized in AOCI and regulatory assets (liabilities) | $ | (824 | ) |
| $ | 1,010 |
| | $ | (110 | ) | | $ | 293 |
|
| $ | 115 |
| | $ | (123 | ) | $ | (3 | ) |
| $ | (824 | ) | | $ | 1,010 |
| | $ | (112 | ) |
| $ | 293 |
| | $ | 115 |
|
| | | | | | | | | | | | | | | | | | | | | | |
Total recognized in AOCI | $ | (401 | ) | | $ | 51 |
| | $ | (64 | ) | | $ | 168 |
| | $ | 20 |
| | $ | (63 | ) | $ | 3 |
| | $ | (401 | ) | | $ | 51 |
| | $ | (55 | ) | | $ | 168 |
| | $ | 20 |
|
Total recognized in regulatory assets (liabilities) | $ | (423 | ) | | $ | 959 |
| | $ | (46 | ) | | $ | 125 |
| | $ | 95 |
| | $ | (60 | ) | $ | (6 | ) | | $ | (423 | ) | | $ | 959 |
| | $ | (57 | ) | | $ | 125 |
| | $ | 95 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | Predecessor | Predecessor |
| Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities): | | | | | | | | | | |
Current year actuarial loss (gain) | $ | — |
| | $ | 50 |
| | $ | — |
| | $ | (39 | ) | $ | — |
| | $ | — |
|
Amortization of actuarial loss | (14 | ) | | (65 | ) | | (2 | ) | | (8 | ) | (14 | ) | | (2 | ) |
Amortization of prior service (cost) credit | — |
| | (2 | ) | | 3 |
| | 13 |
| — |
| | 3 |
|
Total recognized in AOCI and regulatory assets (liabilities) | $ | (14 | ) | | $ | (17 | ) | | $ | 1 |
| | $ | (34 | ) | $ | (14 | ) | | $ | 1 |
|
| | | | | | | | | | |
Total recognized in AOCI | $ | (1 | ) | | $ | (11 | ) | | $ | — |
| | $ | — |
| $ | (1 | ) | | $ | — |
|
Total recognized in regulatory assets (liabilities) | $ | (13 | ) | | $ | (6 | ) | | $ | 1 |
| | $ | (34 | ) | $ | (13 | ) | | $ | 1 |
|
__________
| |
(a) | 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016. |
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 20172018 and 2016,2017, respectively, for all plans combined:
|
| | | | | | | | | | | | | | | |
| Exelon | | Exelon |
| Pension Benefits | | Other Postretirement Benefits |
| 2017 | | 2016(a) | | 2017 | | 2016(a) |
Prior service (credit) cost | $ | (24 | ) |
| $ | (31 | ) | | $ | (522 | ) | | $ | (710 | ) |
Actuarial loss | 7,556 |
| | 8,387 |
| | 829 |
| | 724 |
|
Total (a) | $ | 7,532 |
| | $ | 8,356 |
| | $ | 307 |
| | $ | 14 |
|
| | | | | | | |
Total included in AOCI | $ | 3,896 |
| | $ | 4,297 |
| | $ | 125 |
| | $ | (42 | ) |
Total included in regulatory assets (liabilities) | $ | 3,636 |
| | $ | 4,059 |
| | $ | 182 |
| | $ | 56 |
|
__________
| |
(a) | Effective March 23, 2016, Exelon became the sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | |
| Exelon | | | Exelon |
| Pension Benefits | | | Other Postretirement Benefits |
| 2018 | | 2017 | | | 2018 | | 2017 |
Prior service (credit) cost | $ | (29 | ) |
| $ | (24 | ) | | | $ | (337 | ) | | $ | (522 | ) |
Actuarial loss | 7,558 |
| | 7,556 |
| | | 531 |
| | 829 |
|
Total | $ | 7,529 |
| | $ | 7,532 |
| | | $ | 194 |
| | $ | 307 |
|
| | | | | | | | |
Total included in AOCI | $ | 3,899 |
| | $ | 3,896 |
| | | $ | 70 |
| | $ | 125 |
|
Total included in regulatory assets (liabilities) | $ | 3,630 |
| | $ | 3,636 |
| | | $ | 124 |
| | $ | 182 |
|
The following table provides the impact to Exelon’s AOCI and regulatory assets (liabilities) at December 31, 2017 as a result of the components of periodic benefit costs that are expected to be amortized in 2018. These estimates are subject to the completion of an actuarial valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2018 and actual claims activity as of December 31, 2017. The valuation is expected to be completed in the first quarter of 2018 for the majority of the benefit plans.
|
| | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
Prior service cost (credit) | $ | 2 |
| | $ | (186 | ) |
Actuarial loss | 640 |
| | 66 |
|
Total (a) | $ | 642 |
|
| $ | (120 | ) |
__________
| |
(a) | Of the $642 million related to pension benefits at December 31, 2017, $317 million and $325 million are expected to be amortized from AOCI and regulatory assets in 2018, respectively. Of the $(120) million related to other postretirement benefits at December 31, 2017, $(65) million and $(55) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2018, respectively. |
Average Remaining Service Period
For pension benefits, Exelon amortizes its unrecognized prior service costs and certain actuarial gains and losses, as applicable, based on participants’ average remaining service periods. The average remaining service period of Exelon's defined benefit pension plan participants was 11.812.0 years, 11.911.8 years and 11.9 years for the years ended December 31, 2018, 2017 and 2016, and 2015, respectively. For the predecessor period, the average remaining service period of PHI's defined benefit plans was approximately 11 years for the year ended December 31, 2015.
For other postretirement benefits, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period to benefit eligibility age and amortizes certain actuarial gains and losses over participants’ average remaining service period to expected retirement. The average remaining service period of postretirement benefit plan participants related to benefit eligibility age was 8.28.8 years, 9.08.8 years and 10.89.0 years for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.69.5 years, 9.79.6 years and 9.7 years for the years ended December 31, 2018, 2017 and 2016, and 2015, respectively. For the predecessor period, the average remaining service period of PHI's other postretirement benefit plans was approximately 11 years for the year ended December 31, 2015.
Assumptions
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors. When developing the required assumptions, Exelon considers historical information as well as future expectations.
Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Combined NotesMortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Mortality. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations ofanticipate future improvements in life expectancy. The change wasExelon’s mortality assumption is supported through completion ofby an actuarial experience study of Exelon's plan participants and supplemental analyses performed by Exelon's actuaries.utilizes the IRS's RP–2000 base table projected to 2012 with improvement scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. There were no changes to the mortality assumption in 2015, 2016, 2017 or 2017.2018.
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2018, 2017 2016 and 2015.2016. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
|
| | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits | |
Exelon | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | |
Discount rate | 3.62 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) | 3.61 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) |
Rate of compensation increase | | (d) | | (e) | | (e) | | (d) | | (e) | | (e) |
Mortality table | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| |
Health care cost trend on covered charges | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.50% decreasing to ultimate trend of 5.00% in 2017 | |
| | | Predecessor | | Predecessor | Pension Benefits | | Other Postretirement Benefits | |
| Pension Benefits | | Other Postretirement Benefits | |
PHI | January 1, 2016 to March 23, 2016(f) | | 2015 | | January 1, 2016 to March 23, 2016(e) | | 2015 | |
Exelon | | 2018 | | 2017 | | 2016(f) | | 2018 | | 2017 | | 2016(f) | |
Discount rate | | | 4.65%/4.55% |
| (g) | | | 4.55 | % | 4.31 | % | (a) | 3.62 | % | (b) | 4.04 | % | (c) | 4.30 | % | (a) | 3.61 | % | (b) | 4.04 | % | (c) |
Investment Crediting Rate | | 4.46 | % | | 4.00 | % | | 4.46 | % | | N/A | | N/A | | N/A |
| |
Rate of compensation increase | | 5.00 | % | | 5.00 | % | | (d) | | (d) | | (e) | | (d) | | (d) | | (e) |
Mortality table | | RP-2014 table with improvement scale MP-2015 | | RP-2014 table with improvement scale MP-2015 | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| |
Health care cost trend on covered charges | | N/A | | 6.33% pre-65 and 5.40% post-65 decreasing to ultimate trend of 5.00% in 2020 | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% decreasing to ultimate trend of 5.00% in 2017 | |
__________
| |
(a) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2018. Certain benefit plans used individual rates ranging from 4.13% - 4.36% and 4.27% - 4.38% for pension and other postretirement plans, respectively. |
| |
(b) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2017. Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively. |
| |
(b)(c) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2016. Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively. |
| |
(c) | The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2015. Certain benefit plans used individual rates ranging from 3.68% - 4.14% and 4.32% - 4.43% for pension and other postretirement plans, respectively. |
| |
(d) | 3.25% through 2019 and 3.75% thereafter. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(e) | The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods. |
| |
(f) | Obligation was not remeasured during this period. |
| |
(g) | The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively.PHI predecessor for the period from January 1, 2016, to March 23, 2016. |
The following assumptions were used to determine the net periodic benefit costs for the plans for the years ended December 31, 2018, 2017 2016 and 2015,2016, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:
| | | Pension Benefits | | Other Postretirement Benefits | | Pension Benefits | | Other Postretirement Benefits | |
Exelon | 2017 | | 2016 | | 2015 | | 2017 | | 2016 | | 2015 | | 2018 | | 2017 | | 2016 | | 2018 | | 2017 | | 2016 | |
Discount rate | 4.04 | % | (a) | 4.29 | % | (b) | 3.94 | % | (c) | 4.04 | % | (a) | 4.29 | % | (b) | 3.92 | % | (c) | 3.62 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) | 3.61 | % | (a) | 4.04 | % | (b) | 4.29 | % | (c) |
Investment Crediting Rate | | 4.00 | % | | 4.46 | % | | 5.31 | % | | N/A |
| | N/A |
| | N/A |
| |
Expected return on plan assets | 7.00 | % | (d) | 7.00 | % | (d) | 7.00 | % | (d) | 6.58 | % | (d) | 6.71 | % | (d) | 6.50 | % | (d) | 7.00 | % | (d) | 7.00 | % | (d) | 7.00 | % | (d) | 6.60 | % | (d) | 6.58 | % | (d) | 6.71 | % | (d) |
Rate of compensation increase | |
| (e)
| |
(e) | | (e) | |
|
(e) | | (e)
| | (e)
| |
| (e)
| |
(f) | | (f) | |
|
(e) | | (f)
| | (f)
|
Mortality table | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| | RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)
| |
Health care cost trend on covered charges | N/A | | N/A | | N/A | | 5.00% decreasing to ultimate trend of 5.00% in 2017 | | 5.50% decreasing to ultimate trend of 5.00% in 2017 | | 6.00% decreasing to ultimate trend of 5.00% in 2017 | | N/A | | N/A | | N/A | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.00% with ultimate trend of 5.00% in 2017 | | 5.50% decreasing to ultimate trend of 5.00% in 2017 | |
| | | Predecessor | | Predecessor | Predecessor |
| Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
PHI | January 1, 2016 to March 23, 2016 | | 2015 | | January 1, 2016 to March 23, 2016 | | 2015 | January 1, 2016 to March 23, 2016 | | January 1, 2016 to March 23, 2016 |
Discount rate | 4.65%/4.55% |
| (f) | 4.20 | % | | 4.55 | % | | 4.15 | % | 4.65%/4.55% |
| (g) | 4.55 | % |
Expected return on plan assets(g) | 6.50 | % | | 6.50 | % | | 6.75 | % | | 6.75 | % | |
Investment crediting rate | | 2.89 | % | | N/A |
|
Expected return on plan assets(h) | | 6.50 | % | | 6.75 | % |
Rate of compensation increase | 5.00 | % | | 5.00 | % | | 5.00 | % | | 5.00 | % | 5.00 | % | | 5.00 | % |
Mortality table | RP-2014 table with improvement scale MP-2015
| | RP-2014 table with improvement scale MP-2014 | | RP-2014 table with improvement scale MP-2015 | | RP-2014 table with improvement scale MP-2014 | RP-2014 table with improvement scale MP-2015 | | RP-2014 table with improvement scale MP-2015 |
Health care cost trend on covered charges | N/A | | N/A | | 6.33% pre-65 and 5.40% post-65 decreasing to ultimate trend of 5.00% in 2020
| | 6.67% pre-65 and 5.50% post-65 decreasing to ultimate trend of 5.00% in 2020 | N/A | | 6.33% pre-65 and 5.40% post-65 decreasing to ultimate trend of 5.00% in 2020 |
__________
| |
(a) | The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2017.2018. Certain benefit plans used individual rates ranging from 3.66%-4.11%3.49%-3.65% and 4.00%-4.17%3.57%-3.68% for pension and other postretirement plans, respectively. |
| |
(b) | The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2016.2017. Certain benefit plans used individual rates ranging from 3.68%-4.14%3.66%-4.11% and 4.32%-4.43%4.00%-4.17% for pension and other postretirement plans, respectively. |
| |
(c) | The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015.2016. Certain benefit plans used the individual rates ranging from 3.29%-3.82%3.68%-4.14% and 3.99%-4.06%4.32%-4.43% for pension and other postretirement plans, respectively. |
| |
(d) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(d) | Not applicable to pension and other postretirement benefit plans that do not have plan assets. |
| |
(e) | 3.25% through 2019 and 3.75% thereafter. |
| |
(f) | The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods. |
| |
(f)(g) | The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively. |
| |
(g)(h) | Expected return on other postretirement benefit plan assets is pre-tax. |
Assumed health care cost trend rates impact the other postretirement benefit plan costs reported for Exelon's participant populations with plan designs that do not have a cap on cost growth. A one percentage point change in assumed health care cost trend rates would have the following effects:
|
| | | |
Effect of a one percentage point increase in assumed health care cost trend: | |
on 2017 total service and interest cost components | $ | 9 |
|
on postretirement benefit obligation at December 31, 2017 | 125 |
|
Effect of a one percentage point decrease in assumed health care cost trend: | |
on 2017 total service and interest cost components | (8 | ) |
on postretirement benefit obligation at December 31, 2017 | (113 | ) |
Contributions
The following tables provide contributions to the pension and other postretirement benefit plans:
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
| 2017(a) | | 2016(a) | | 2015(a) | | 2017 | | 2016 | | 2015 | 2018(a) | | 2017(a) | | 2016(a) | | 2018 | | 2017 | | 2016 |
Exelon | $ | 341 |
|
| $ | 347 |
|
| $ | 462 |
|
| $ | 64 |
|
| $ | 50 |
|
| $ | 40 |
| $ | 337 |
|
| $ | 341 |
|
| $ | 347 |
|
| $ | 46 |
|
| $ | 64 |
|
| $ | 50 |
|
Generation | 137 |
| | 140 |
| | 231 |
| | 11 |
| | 12 |
| | 14 |
| 128 |
| | 137 |
| | 140 |
| | 11 |
| | 11 |
| | 12 |
|
ComEd | 36 |
| | 33 |
| | 143 |
| | 5 |
| | 5 |
| | 7 |
| 38 |
| | 36 |
| | 33 |
| | 4 |
| | 5 |
| | 5 |
|
PECO | 24 |
| | 30 |
| | 40 |
| | — |
| | — |
| | — |
| 28 |
| | 24 |
| | 30 |
| | — |
| | — |
| | — |
|
BGE | 39 |
| | 31 |
| | 1 |
| | 14 |
| | 18 |
| | 16 |
| 40 |
| | 39 |
| | 31 |
| | 14 |
| | 14 |
| | 18 |
|
BSC(b) | 38 |
| | 39 |
| | 47 |
| | 2 |
| | 3 |
| | 3 |
| 41 |
| | 38 |
| | 39 |
| | 5 |
| | 2 |
| | 3 |
|
Pepco | 62 |
| | 24 |
| | — |
| | 10 |
| | 8 |
| | 2 |
| 6 |
| | 62 |
| | 24 |
| | 11 |
| | 10 |
| | 8 |
|
DPL | — |
| | 22 |
| | — |
| | 2 |
| | — |
| | — |
| — |
| | — |
| | 22 |
| | — |
| | 2 |
| | — |
|
ACE | — |
| | 15 |
| | — |
| | 20 |
| | 2 |
| | 3 |
| 6 |
| | — |
| | 15 |
| | — |
| | 20 |
| | 2 |
|
PHISCO (c) | 5 |
| | 17 |
| | — |
| | — |
| | 2 |
| | — |
| 50 |
| | 5 |
| | 17 |
| | 1 |
| | — |
| | 2 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| Successor | | | Predecessor | | Successor | | | Predecessor |
| 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 |
PHI | $ | 67 |
| | $ | 74 |
| | | $ | 4 |
| | $ | — |
| | $ | 32 |
| | $ | 12 |
| | | $ | — |
| | $ | 5 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension Benefits | | Other Postretirement Benefits |
| Successor | | | Predecessor | | Successor | | | Predecessor |
| 2018 | | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | 2018 | | 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | $ | 62 |
| | $ | 67 |
| | $ | 74 |
| | | $ | 4 |
| | $ | 12 |
| | $ | 32 |
| | $ | 12 |
| | | $ | — |
|
__________
| |
(a) | Exelon's and Generation's pension contributions include $21 million $25 million and $36$25 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2017 and 2016, and 2015, respectively. There were no pension contributions for the year ended December 31, 2018. |
| |
(b) | Includes $2 million, $4 million, $6 million, and $5$6 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively. |
| |
(c) | PHISCO’s pension contributions for the year ended December 31, 2016 include $4 million of contributions made prior to the closing of Exelon’s merger with PHI on March 23, 2016. |
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act),
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy of contributing the greater of (1) $300 million (which has been updated for the inclusion of PHI) until all the qualified plans are fully funded on an ABO basis, and (2) the minimum amounts under ERISA to meet minimum contribution requirement and/or avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While other postretirement plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB plans, contributions generally equal accounting costs, however,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and planned contributions to other postretirement plans in 2018:2019:
|
| | | | | | | | | | | |
| Qualified Pension Plans |
| Non-Qualified Pension Plans |
| Other Postretirement Benefits |
Exelon | $ | 301 |
|
| $ | 30 |
|
| $ | 42 |
|
Generation | 119 |
|
| 11 |
|
| 13 |
|
ComEd | 38 |
|
| 2 |
|
| 3 |
|
PECO | 17 |
|
| 1 |
|
| — |
|
BGE | 41 |
|
| 1 |
|
| 16 |
|
BSC | 36 |
|
| 7 |
|
| 1 |
|
PHI | 50 |
|
| 8 |
|
| 9 |
|
Pepco | 4 |
|
| 2 |
|
| 8 |
|
DPL | — |
|
| 1 |
|
| — |
|
ACE | 6 |
|
| — |
|
| — |
|
PHISCO | 40 |
|
| 5 |
|
| 1 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | |
| Qualified Pension Plans |
| Non-Qualified Pension Plans |
| Other Postretirement Benefits |
Exelon | $ | 301 |
|
| $ | 25 |
|
| $ | 44 |
|
Generation | 135 |
|
| 7 |
|
| 13 |
|
ComEd | 65 |
|
| 1 |
|
| 2 |
|
PECO | 25 |
|
| 1 |
|
| — |
|
BGE | 34 |
|
| 1 |
|
| 15 |
|
BSC | 41 |
|
| 7 |
|
| 2 |
|
PHI | 1 |
|
| 8 |
|
| 12 |
|
Pepco | — |
|
| 2 |
|
| 10 |
|
DPL | — |
|
| 1 |
|
| — |
|
ACE | — |
|
| — |
|
| 1 |
|
PHISCO | 1 |
|
| 5 |
|
| 1 |
|
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 20172018 were:
| | | Pension Benefits | | Other Postretirement Benefits | Pension Benefits | | Other Postretirement Benefits |
2018 | $ | 1,166 |
| | $ | 256 |
| |
2019 | 1,165 |
| | 262 |
| $ | 1,196 |
| | $ | 255 |
|
2020 | 1,210 |
| | 270 |
| 1,221 |
| | 263 |
|
2021 | 1,236 |
| | 276 |
| 1,258 |
| | 269 |
|
2022 | 1,265 |
| | 284 |
| 1,284 |
| | 274 |
|
2023 through 2027 | 6,671 |
| | 1,509 |
| |
Total estimated future benefit payments through 2027 | $ | 12,713 |
|
| $ | 2,857 |
| |
2023 | | 1,302 |
| | 282 |
|
2024 through 2028 | | 6,770 |
| | 1,483 |
|
Total estimated future benefit payments through 2028 | | $ | 13,031 |
|
| $ | 2,826 |
|
Allocation to Exelon Subsidiaries
All registrants account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each plan. Pension and other postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon began allocating costs related to its legacy Exelon pension and other postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are allocated based on accounting cost. The impact of this allocation methodology change was not material to any Registrant. For legacy CEG, legacy
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
CENG, FitzPatrick, and legacy PHI plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired).
The amounts below were included in capital expendituresrepresent the Registrants’ as well as BSC's and operatingPHISCO's pension and maintenance expenseOPEB costs. As a result of new pension guidance effective on January 1, 2018, certain balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2017 and 2016. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment, net, for the years ended December 31, 2018, 2017 and 2016, while the non–service cost components are included in Other, net and 2015, respectively,Regulatory assets for each ofyear ended December 31, 2018 and in Other, net and Property, plant and equipment, net, for the entities allocated portion ofyears ended December 31, 2017 and 2016. For Generation and the pensionUtility Registrants, the service cost and other postretirement benefit plan costs. These amounts includenon–service cost components are included in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements for the recognized contractual termination benefit charges, curtailment gains,years ended December 31, 2018, 2017 and settlement charges:2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
For the Years Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE(c) | | PHISCO(c)(d) |
2017 | $ | 643 |
| | $ | 227 |
|
| $ | 176 |
|
| $ | 29 |
| | $ | 64 |
| | $ | 53 |
| | $ | 25 |
| | $ | 13 |
| | $ | 13 |
| | $ | 43 |
|
2016 | 621 |
| | 218 |
|
| 166 |
|
| 33 |
| | 68 |
| | 48 |
| | 31 |
| | 18 |
| | 15 |
| | 47 |
|
2015 | 637 |
| | 269 |
|
| 206 |
|
| 39 |
| | 66 |
| | 57 |
| | 30 |
| | 15 |
| | 15 |
| | 37 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
For the Years Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE(c) | | PHISCO(c)(d) |
2018 | $ | 583 |
| | $ | 204 |
|
| $ | 177 |
|
| $ | 18 |
| | $ | 60 |
| | $ | 57 |
| | $ | 15 |
| | $ | 6 |
| | $ | 12 |
| | $ | 34 |
|
2017 | 643 |
| | 227 |
|
| 176 |
|
| 29 |
| | 64 |
| | 53 |
| | 25 |
| | 13 |
| | 13 |
| | 43 |
|
2016 | 621 |
| | 218 |
|
| 166 |
|
| 33 |
| | 68 |
| | 48 |
| | 31 |
| | 18 |
| | 15 |
| | 47 |
|
| | | Successor | | | Predecessor | Successor | | Predecessor |
PHI | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Pension and Other Postretirement Benefit Costs | $ | 94 |
| | $ | 88 |
| | | $ | 23 |
| | $ | 97 |
| $ | 67 |
| | $ | 94 |
| | $ | 88 |
| | | $ | 23 |
|
__________
| |
(a) | FitzPatrick net benefit costs are included for the period after acquisition. |
| |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(c) | Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the year ended December 31, 2016 include $7 million, $4 million,, $3 $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. |
| |
(d) | These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above. |
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and other postretirement benefit plans. The actual asset returns across Exelon’s pension and other postretirement benefit plans for the year ended December 31, 20172018 were 16.10%(4.86)% and 14.70%(4.66)%, respectively, compared to an expected long-term return assumption of 7.00% and 6.58%6.60%, respectively.
Exelon used an EROA of 7.00% and 6.60%6.67% to estimate its 20182019 pension and other postretirement benefit costs, respectively.
Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2017 and 2016 asset allocations were as follows:
Pension Plans
|
| | | | | | | | |
| | | Exelon |
| | | Percentage of Plan Assets at December 31, |
Asset Category | Target Allocation | | 2017 | | 2016 |
Equity securities | 35 | % | | 35 | % | | 33 | % |
Fixed income securities | 38 | % | | 39 |
| | 39 |
|
Alternative investments(a) | 27 | % | | 26 |
| | 28 |
|
Total | | | 100 | % | | 100 | % |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2018 and 2017 asset allocations were as follows:
Pension Plans
|
| | | | | | | | |
| | | Exelon |
| | | Percentage of Plan Assets at December 31, |
Asset Category | Target Allocation | | 2018 | | 2017 |
Equity securities | 35 | % | | 32 | % | | 35 | % |
Fixed income securities | 37 | % | | 38 |
| | 39 |
|
Alternative investments(a) | 28 | % | | 30 |
| | 26 |
|
Total | | | 100 | % | | 100 | % |
Other Postretirement Benefit Plans
| | | | | Exelon | | | Exelon |
| | | Percentage of Plan Assets at December 31, | | | Percentage of Plan Assets at December 31, |
Asset Category | Target Allocation | | 2017 | | 2016 | Target Allocation | | 2018 | | 2017 |
Equity securities | 46 | % | | 47 | % | | 47 | % | 47 | % | | 44 | % | | 47 | % |
Fixed income securities | 28 | % | | 28 |
| | 29 |
| 28 | % | | 28 |
| | 28 |
|
Alternative investments(a) | 26 | % | | 25 |
| | 24 |
| 25 | % | | 28 |
| | 25 |
|
Total | | | 100 | % | | 100 | % | | | 100 | % | | 100 | % |
__________ | |
(a) | Alternative investments include private equity, hedge funds, real estate, and private credit. |
Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2017.2018. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2017,2018, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair Value Measurements
The following tables present pension and other postretirement benefit plan assets measured and recorded at fair value onin the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 20172018 and 2016:2017:
Exelon
| | December 31, 2017(a)(b) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | |
December 31, 2018(a) | | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets | | | | | | | | | | | | | | | | | | |
Cash equivalents | $ | 585 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 585 |
| $ | 350 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 350 |
|
Equities(c) | 3,565 |
| | — |
| | 2 |
| | 3,077 |
| | 6,644 |
| 3,364 |
| | — |
| | 2 |
| | 1,980 |
| | 5,346 |
|
Fixed income: |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
|
U.S. Treasury and agencies | 1,150 |
| | 159 |
| | — |
| | — |
| | 1,309 |
| 996 |
| | 173 |
| | — |
| | — |
| | 1,169 |
|
State and municipal debt | — |
| | 64 |
| | — |
| | — |
| | 64 |
| — |
| | 59 |
| | — |
| | — |
| | 59 |
|
Corporate debt | — |
| | 3,931 |
| | 232 |
| | — |
| | 4,163 |
| — |
| | 3,716 |
| | 216 |
| | — |
| | 3,932 |
|
Other(c) | — |
| | 447 |
| | — |
| | 756 |
| | 1,203 |
| — |
| | 329 |
| | — |
| | 613 |
| | 942 |
|
Fixed income subtotal | 1,150 |
|
| 4,601 |
|
| 232 |
| | 756 |
| | 6,739 |
| 996 |
|
| 4,277 |
|
| 216 |
| | 613 |
| | 6,102 |
|
Private equity | — |
| | — |
| | — |
| | 1,034 |
| | 1,034 |
| — |
| | — |
| | — |
| | 1,219 |
| | 1,219 |
|
Hedge funds | — |
| | — |
| | — |
| | 1,770 |
| | 1,770 |
| — |
| | — |
| | — |
| | 1,608 |
| | 1,608 |
|
Real estate | — |
| | — |
| | — |
| | 884 |
| | 884 |
| — |
| | — |
| | — |
| | 1,029 |
| | 1,029 |
|
Private credit | — |
| | — |
| | — |
| | 919 |
| | 919 |
| — |
| | — |
| | 268 |
| | 798 |
| | 1,066 |
|
Pension plan assets subtotal | $ | 5,300 |
|
| $ | 4,601 |
|
| $ | 234 |
| | $ | 8,440 |
| | $ | 18,575 |
| $ | 4,710 |
|
| $ | 4,277 |
|
| $ | 486 |
| | $ | 7,247 |
| | $ | 16,720 |
|
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2018(a) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Other postretirement benefit plan assets | | | | | | | | | |
Cash equivalents | $ | 22 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 22 |
|
Equities | 537 |
| | 2 |
| | — |
| | 508 |
| | 1,047 |
|
Fixed income: |
|
|
|
|
| | | |
|
U.S. Treasury and agencies | 11 |
| | 56 |
| | — |
| | — |
| | 67 |
|
State and municipal debt | — |
| | 126 |
| | — |
| | — |
| | 126 |
|
Corporate debt | — |
| | 48 |
| | — |
| | — |
| | 48 |
|
Other | 183 |
| | 72 |
| | — |
| | 170 |
| | 425 |
|
Fixed income subtotal | 194 |
|
| 302 |
|
| — |
|
| 170 |
| | 666 |
|
Hedge funds | — |
| | — |
| | — |
| | 411 |
| | 411 |
|
Real estate | — |
| | — |
| | — |
| | 132 |
| | 132 |
|
Private credit | — |
| | — |
| | — |
| | 132 |
| | 132 |
|
Other postretirement benefit plan assets subtotal | $ | 753 |
|
| $ | 304 |
|
| $ | — |
| | $ | 1,353 |
|
| $ | 2,410 |
|
Total pension and other postretirement benefit plan assets(e) | $ | 5,463 |
| | $ | 4,581 |
| | $ | 486 |
| | $ | 8,600 |
| | $ | 19,130 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2017(a)(b) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets | | | | | | | | | |
Cash equivalents | $ | 585 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 585 |
|
Equities(c) | 3,565 |
| | — |
| | 2 |
| | 3,077 |
| | 6,644 |
|
Fixed income: |
|
| |
|
| |
|
| | | |
|
|
U.S. Treasury and agencies | 1,150 |
| | 159 |
| | — |
| | — |
| | 1,309 |
|
State and municipal debt | — |
| | 64 |
| | — |
| | — |
| | 64 |
|
Corporate debt | — |
| | 3,931 |
| | 232 |
| | — |
| | 4,163 |
|
Other(c) | — |
| | 447 |
| | — |
| | 756 |
| | 1,203 |
|
Fixed income subtotal | 1,150 |
|
| 4,601 |
|
| 232 |
| | 756 |
| | 6,739 |
|
Private equity | — |
| | — |
| | — |
| | 1,034 |
| | 1,034 |
|
Hedge funds | — |
| | — |
| | — |
| | 1,770 |
| | 1,770 |
|
Real estate | — |
| | — |
| | — |
| | 884 |
| | 884 |
|
Private credit(d) | — |
| | — |
| | 224 |
| | 695 |
| | 919 |
|
Pension plan assets subtotal | $ | 5,300 |
|
| $ | 4,601 |
|
| $ | 458 |
| | $ | 8,216 |
|
| $ | 18,575 |
|
| | December 31, 2017(a)(b) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Other postretirement benefit plan assets | | | | | | | | | | | | | | | | | | |
Cash equivalents | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
| $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 29 |
|
Equities | 523 |
| | 2 |
| | — |
| | 764 |
| | 1,289 |
| 523 |
| | 2 |
| | — |
| | 764 |
| | 1,289 |
|
Fixed income: |
|
|
|
|
| | | |
|
|
|
|
|
| | | |
|
U.S. Treasury and agencies | 13 |
| | 56 |
| | — |
| | — |
| | 69 |
| 13 |
| | 56 |
| | — |
| | — |
| | 69 |
|
State and municipal debt | — |
| | 136 |
| | — |
| | — |
| | 136 |
| — |
| | 136 |
| | — |
| | — |
| | 136 |
|
Corporate debt | — |
| | 47 |
| | — |
| | — |
| | 47 |
| — |
| | 47 |
| | — |
| | — |
| | 47 |
|
Other | 225 |
| | 71 |
| | — |
| | 185 |
| | 481 |
| 225 |
| | 71 |
| | — |
| | 185 |
| | 481 |
|
Fixed income subtotal | 238 |
|
| 310 |
|
| — |
|
| 185 |
| | 733 |
| 238 |
|
| 310 |
|
| — |
| | 185 |
| | 733 |
|
Hedge funds | — |
| | — |
| | — |
| | 430 |
| | 430 |
| — |
| | — |
| | — |
| | 430 |
| | 430 |
|
Real estate | — |
| | — |
| | — |
| | 124 |
| | 124 |
| — |
| | — |
| | — |
| | 124 |
| | 124 |
|
Private credit | — |
| | — |
| | — |
| | 123 |
| | 123 |
| — |
| | — |
| | — |
| | 123 |
| | 123 |
|
Other postretirement benefit plan assets subtotal | $ | 790 |
|
| $ | 312 |
|
| $ | — |
| | $ | 1,626 |
|
| $ | 2,728 |
| $ | 790 |
|
| $ | 312 |
|
| $ | — |
| | $ | 1,626 |
| | $ | 2,728 |
|
Total pension and other postretirement benefit plan assets(d)(e) | $ | 6,090 |
| | $ | 4,913 |
| | $ | 234 |
| | $ | 10,066 |
| | $ | 21,303 |
| $ | 6,090 |
| | $ | 4,913 |
| | $ | 458 |
| | $ | 9,842 |
| | $ | 21,303 |
|
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2016(a)(e) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Pension plan assets | | | | | | | | | |
Cash equivalents | $ | 325 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 325 |
|
Equities(c) | 3,144 |
| | — |
| | 2 |
| | 2,535 |
| | 5,681 |
|
Fixed income: |
|
| |
|
| |
|
| | | |
|
|
U.S. Treasury and agencies | 1,008 |
| | 192 |
| | — |
| | — |
| | 1,200 |
|
State and municipal debt | — |
| | 64 |
| | — |
| | — |
| | 64 |
|
Corporate debt | — |
| | 3,641 |
| | 206 |
| | — |
| | 3,847 |
|
Other(c) | — |
| | 340 |
| | — |
| | 748 |
| | 1,088 |
|
Fixed income subtotal | 1,008 |
|
| 4,237 |
|
| 206 |
| | 748 |
| | 6,199 |
|
Private equity | — |
| | — |
| | — |
| | 991 |
| | 991 |
|
Hedge funds | — |
| | — |
| | — |
| | 1,962 |
| | 1,962 |
|
Real estate | — |
| | — |
| | — |
| | 828 |
| | 828 |
|
Private credit | — |
| | — |
| | — |
| | 833 |
| | 833 |
|
Pension plan assets subtotal | $ | 4,477 |
|
| $ | 4,237 |
|
| $ | 208 |
| | $ | 7,897 |
|
| $ | 16,819 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
December 31, 2016(a)(e) | Level 1 | | Level 2 | | Level 3 | | Not subject to leveling | | Total |
Other postretirement benefit plan assets | | | | | | | | | |
Cash equivalents | $ | 24 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 24 |
|
Equities | 547 |
| | 2 |
| | — |
| | 644 |
| | 1,193 |
|
Fixed income: |
|
|
|
|
| | | |
|
U.S. Treasury and agencies | 9 |
| | 59 |
| | — |
| | — |
| | 68 |
|
State and municipal debt | — |
| | 134 |
| | — |
| | — |
| | 134 |
|
Corporate debt | — |
| | 43 |
| | — |
| | — |
| | 43 |
|
Other | 256 |
| | 60 |
| | — |
| | 131 |
| | 447 |
|
Fixed income subtotal | 265 |
|
| 296 |
|
| — |
| | 131 |
| | 692 |
|
Hedge funds | — |
| | — |
| | — |
| | 445 |
| | 445 |
|
Real estate | — |
| | — |
| | — |
| | 117 |
| | 117 |
|
Private credit | — |
| | — |
| | — |
| | 107 |
| | 107 |
|
Other postretirement benefit plan assets subtotal | $ | 836 |
|
| $ | 298 |
|
| $ | — |
| | $ | 1,444 |
| | $ | 2,578 |
|
Total pension and other postretirement benefit plan assets(d) | $ | 5,313 |
| | $ | 4,535 |
| | $ | 208 |
| | $ | 9,341 |
| | $ | 19,397 |
|
__________
| |
(a) | See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy. |
| |
(b) | Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations. |
| |
(c) | Includes derivative instruments of $6less than $1 million and $1$6 million, which have a total notional amount of $3,606$5,991 million and $2,918$3,606 million at December 31, 20172018 and 2016,2017, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss. |
| |
(d) | Prior year amounts reflect a reclassification from Not subject to leveling into Level 3. |
| |
(e) | Excludes net liabilities of $44 million and net assets of $2 million and net liabilities of $28 million at December 31, 20172018 and 2016,2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable, and payables related to pending securities purchases.receivable. |
| |
(e) | Effective March 23, 2016, Exelon became sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 20172018 and 2016:2017:
Exelon
|
| | | | | | | | | | | |
| Fixed Income | | Equities | | Total |
Pension Assets | | | | | |
Balance as of January 1, 2017 | $ | 206 |
|
| $ | 2 |
| | $ | 208 |
|
Actual return on plan assets: |
|
|
| |
|
|
Relating to assets sold during the period | 11 |
|
| — |
| | 11 |
|
Purchases, sales and settlements: |
|
|
| |
|
|
Purchases | 31 |
|
| — |
| | 31 |
|
Sales | (16 | ) |
| — |
| | (16 | ) |
Settlements(a) | — |
|
| — |
| | — |
|
Balance as of December 31, 2017 | $ | 232 |
|
| $ | 2 |
| | $ | 234 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | |
| Fixed Income | | Equities | | Private Credit | | Total |
Pension Assets | | | | | | | |
Balance as of January 1, 2018 | $ | 232 |
|
| $ | 2 |
| | $ | 224 |
| | $ | 458 |
|
Actual return on plan assets: |
|
|
| | | |
|
|
Relating to assets still held at the reporting date | (14 | ) |
| — |
| | 9 |
| | (5 | ) |
Relating to assets sold during the period | (1 | ) |
| — |
| | — |
| | (1 | ) |
Purchases, sales and settlements: |
|
|
| | | |
|
|
Purchases | 19 |
|
| — |
| | 35 |
| | 54 |
|
Sales | (8 | ) |
| — |
| | — |
| | (8 | ) |
Settlements(b) | (12 | ) |
| — |
| | — |
| | (12 | ) |
Balance as of December 31, 2018 | $ | 216 |
|
| $ | 2 |
| | $ | 268 |
| | $ | 486 |
|
| | | Fixed income | | Equities | | Total | Fixed income | | Equities | | Private Credit (a) | | Total |
Pension Assets | | | | | | | | | | | | |
Balance as of January 1, 2016 | $ | 165 |
|
| $ | 2 |
| | $ | 167 |
| |
Balance as of January 1, 2017 | | $ | 206 |
|
| $ | 2 |
| | $ | 229 |
| | $ | 437 |
|
Actual return on plan assets: |
|
|
| |
|
|
|
|
| | | |
|
|
Relating to assets still held at the reporting date | (2 | ) |
| — |
| | (2 | ) | 11 |
|
| — |
| | 29 |
| | 40 |
|
Purchases, sales and settlements: |
|
|
| |
|
|
|
|
| | | |
|
|
Purchases | 69 |
|
| — |
| | 69 |
| 31 |
|
| — |
| | 5 |
| | 36 |
|
Sales | (14 | ) |
| — |
| | (14 | ) | (16 | ) |
| — |
| | — |
| | (16 | ) |
Settlements(a)(b) | (12 | ) |
| — |
| | (12 | ) | — |
|
| — |
| | (39 | ) | | (39 | ) |
Balance as of December 31, 2016 | $ | 206 |
|
| $ | 2 |
| | $ | 208 |
| |
Balance as of December 31, 2017 | | $ | 232 |
|
| $ | 2 |
|
| $ | 224 |
| | $ | 458 |
|
__________
| |
(a) | Prior year amounts reflect a reclassification from Not subject to leveling into Level 3. |
| |
(b) | Represents cash settlements only. |
There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 20172018 for the pension and other postretirement benefit plan assets.
Valuation Techniques Used to Determine Fair Value
Cash equivalentsequivalents.. Investments with original maturities of three months or less when purchased, including certain short-term fixed income securities and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
EquitiesEquities.. Equities consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
markets and are categorized as Level 1. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and certain investments are held in accordance with a stated set of fund objectives, which are consistent with the plans’ overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Fixed incomeincome.. For fixed income securities, which consist primarily of corporate debt securities, U.S government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.
Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.
Derivative instruments consisting primarily of futures and swaps to manage risk are recorded at fair value. Over-the-counter derivatives are valued daily based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Private equityequity.. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Hedge fundsfunds.. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Real estateestate.. Real estate funds are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Private credit. Private credit investments primarily consist of limited partnerships that invest in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. Private credit investments are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. The fair value of private credit investments isfunds are determined using NAV or its
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Defined Contribution Savings Plan (All Registrants)
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | For the Year Ended December 31, | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE | | PHISCO(c)(d) | Exelon(a) | | Generation(a) | | ComEd | | PECO | | BGE | | BSC(b) | | Pepco(c) | | DPL(c) | | ACE | | PHISCO(c)(d) |
2018 | | $ | 179 |
| | $ | 86 |
|
| $ | 37 |
|
| $ | 9 |
|
| $ | 12 |
|
| $ | 22 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
| | $ | 6 |
|
2017 | $ | 128 |
| | $ | 55 |
|
| $ | 31 |
|
| $ | 10 |
|
| $ | 10 |
|
| $ | 9 |
| | $ | 3 |
| | $ | 2 |
| | $ | 2 |
| | $ | 6 |
| 128 |
| | 55 |
|
| 31 |
|
| 10 |
|
| 10 |
|
| 9 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
|
2016 | 164 |
| | 79 |
|
| 34 |
|
| 10 |
|
| 12 |
|
| 19 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
| 164 |
| | 79 |
|
| 34 |
|
| 10 |
|
| 12 |
|
| 19 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
|
2015 | 148 |
| | 80 |
|
| 32 |
|
| 11 |
|
| 14 |
|
| 11 |
| | 3 |
| | 2 |
| | 2 |
| | 6 |
| |
| | | Successor | | | Predecessor | Successor | | | Predecessor |
PHI | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Saving Plan Matching Contributions | $ | 13 |
| | $ | 10 |
| | | $ | 3 |
| | $ | 14 |
| $ | 13 |
| | $ | 13 |
| | $ | 10 |
| | | $ | 3 |
|
__________
| |
(a) | Includes $13 million and $9 million related to CENG for the yearsyear ended December 31, 2016 and December 31, 2015.2016. |
| |
(b) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above. |
| |
(c) | Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016. |
| |
(d) | These amounts primarily represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above. |
17. Severance (All Registrants)
The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the 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 years ended December 31, 2017 and 2016, the Registrants recorded the following severance costs associated with ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Severance Liability
Amounts included in the table below represent the severance liability recorded for employees of each Registrant. Exelon's severance liability includes amounts related to BSC that are billed through intercompany allocations.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation(a) | | ComEd(a) | | PECO(a) | | BGE(a) | | PHI(a) | | Pepco(a) | | DPL(a) | | ACE(a) |
Year ended December 31, | | | | | | | | | | | | | | | | | |
2017 | $ | 14 |
| | $ | 6 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | 4 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
|
2016 | 19 |
| | 13 |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Severance Liability | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Balance at December 31, 2016 | $ | 88 |
| | $ | 36 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance costs(a) | 35 |
| | 31 |
| | 2 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Payments | (29 | ) | | (9 | ) | | (2 | ) | | — |
| | — |
| | (12 | ) | | — |
| | — |
| | — |
|
Balance at December 31, 2017 | $ | 94 |
| | $ | 58 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 20 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance costs(a) | 35 |
| | 9 |
| | 1 |
| | — |
| | 1 |
| | 5 |
| | 1 |
| | — |
| | — |
|
Payments | (52 | ) | | (20 | ) | | (2 | ) | | — |
| | — |
| | (18 | ) | | (1 | ) | | — |
| | — |
|
Balance at December 31, 2018 | $ | 77 |
|
| $ | 47 |
|
| $ | 2 |
|
| $ | — |
|
| $ | 1 |
|
| $ | 7 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
__________
| |
(a) | The amounts above for Generation, ComEd, PECO, BGE,Includes salary continuance and PHI include immaterial amounts billed by BSC for the years ended December 31, 2017health and 2016. Pepco, DPL, and ACE include immaterial amounts billed by PHISCO for the year ended December 31, 2017. Pepco, DPL, and ACE did not have any ongoingwelfare severance plans for the year ended December 31, 2016.benefits. |
Cost Management Program-Related Severance
In August 2015, Exelon announced a cost management program focused on cost savings of approximately $400 million at BSC and Generation. Additionally, in November 2017, Exelon announced a new commitment for an additional $250 million of cost savings, primarily at Generation, to be achieved by 2020. 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. In connection with the program, certain positions have been identified for elimination and severance costs were recognized as both probable and estimable.
While there may be additional position eliminations identified leading to potential severance or other termination benefit changes, Exelon, Generation and BSC intend to manage any staff reductions through natural attrition to the extent possible to minimize impacts on employees. Any additional severance or other termination benefit charges related to this commitment will be recognized when such amounts are considered probable and can be reasonably estimated.
For the years ended December 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 Statements of Operations:
|
| | | | | | | | | | | | | | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE |
2017(a) | $ | 6 |
| | $ | 9 |
| | $ | (1 | ) | | $ | (1 | ) | | $ | (1 | ) |
2016(b) | 23 |
| | 18 |
| | 3 |
| | 1 |
| | 1 |
|
__________
| |
(a) | The amounts for Generation, ComEd, PECO, and BGE include $(4) million, $(2) million, $(1) million, and $(1) million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2017. |
| |
(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 year ended December 31, 2016. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Early Plant Retirement-Related Severance (Exelon and Generation)
As a result of the Three Mile Island plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance costs will be provided to management employees that are eligible under the Company's severance policy, to the extent that those employees are not redeployed to other locations. In June 2017, Exelon and Generation recognized severance costs of $17 million related to expected management employee severances resulting from the plant retirements within Operating and maintenance expense in their Consolidated Statements of Operation and Comprehensive Income. Approximately half of the employees at this location fall under a collective bargaining union agreement and are not eligible for severance benefits under an existing plan. The union and Exelon will negotiate terms of any severance benefits. If severance benefits are successfully negotiated, the amounts will be accrued as a one-time employee termination benefit once the established plan is communicated to employees. The final amount of the severance cost will ultimately depend on the specific employees severed. See Note 8 - Early Nuclear Plant Retirements for additional information regarding the announced early retirement of TMI. See Note 28 - Subsequent Events for additional information regarding the early retirement of Oyster Creek.
Severance Costs Related to the PHI Merger
Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.
For the yearyears ended December 31, 2018 and December 31, 2017, the PHI Merger severance costs were immaterial. For the year ended December 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:Income:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Severance Benefits | | | | | | | | | | | | | | | | | |
Severance costs(a) | $ | 57 |
| | $ | 9 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 44 |
| | $ | 21 |
| | $ | 13 |
| | $ | 10 |
|
__________ |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Severance Benefits | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Severance costs(a) | $ | 57 |
| | $ | 9 |
| | $ | 2 |
| | $ | 1 |
| | $ | 1 |
| | $ | 44 |
| | $ | 21 |
| | $ | 13 |
| | $ | 10 |
|
| |
(a) | The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8$8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.allocations. |
PHI, Pepco, DPL and ACE recordrecorded regulatory assets for merger related integration costs which include a portion of thethese severance costs in the table above related to the PHI Merger.costs. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 34 — Regulatory Matters for furtheradditional information.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Severance Liability
Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
Severance Liability | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Balance at December 31, 2015 | $ | 35 |
| | $ | 23 |
| | $ | 3 |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance charges(a) | 99 |
| | 22 |
| | 2 |
| | — |
| | — |
| | 56 |
| | 1 |
| | 1 |
| | — |
|
Payments | (46 | ) | | (9 | ) | | (2 | ) | | — |
| | (1 | ) | | (27 | ) | | (1 | ) | | (1 | ) | | — |
|
Balance at December 31, 2016 | $ | 88 |
| | $ | 36 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | 29 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Severance charges(a) | 35 |
| | 31 |
| | 2 |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Payments | (29 | ) | | (9 | ) | | (2 | ) | | — |
| | — |
| | (12 | ) | | — |
| | — |
| | — |
|
Balance at December 31, 2017 | $ | 94 |
|
| $ | 58 |
|
| $ | 3 |
|
| $ | — |
|
| $ | — |
|
| $ | 20 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
__________
| |
(a) | Includes salary continuance and health and welfare severance benefits. |
18. Mezzanine Equity (Exelon, Generation and PHI)
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 were 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 was presented in mezzanine equity on the consolidated balance sheet.
There were no changes in the contingently redeemable noncontrolling interests for the year ended December 31, 2017. The following table summarizes the changes in the contingently redeemable noncontrolling interests for the year ended December 31, 2016:
|
| | | |
| Contingently Redeemable NCI |
Balance at December 31, 2015 | $ | 28 |
|
Cash received from noncontrolling interests | 129 |
|
Release of contingency | (157 | ) |
Balance at December 31, 2016 | $ | — |
|
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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 the Consolidated Balance Sheet. 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, net within PHI's predecessor period, January 1, 2016 to March 23, 2016, 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.
19. Shareholders' Equity (Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE)
The following table presents common stock authorized and outstanding as of December 31, 20172018 and 2016:2017:
| | | | | | | December 31, | | | | | December 31, |
| | | | | 2017 | | 2016 | | | | | 2018 | | 2017 |
| Par Value | | Shares Authorized | | Shares Outstanding | Par Value | | Shares Authorized | | Shares Outstanding |
Common Stock | | | | | | | | | | | | | | |
Exelon | no par value |
| | 2,000,000,000 |
| | 963,335,888 |
| | 924,035,059 |
| no par value |
| | 2,000,000,000 |
| | 968,187,955 |
| | 963,335,888 |
|
ComEd | $ | 12.50 |
| | 250,000,000 |
| | 127,021,246 |
| | 127,017,157 |
| $ | 12.50 |
| | 250,000,000 |
| | 127,021,331 |
| | 127,021,246 |
|
PECO | no par value |
| | 500,000,000 |
| | 170,478,507 |
| | 170,478,507 |
| no par value |
| | 500,000,000 |
| | 170,478,507 |
| | 170,478,507 |
|
BGE | no par value |
| | 1,500 |
| | 1,000 |
| | 1,000 |
| no par value |
| | 1,500 |
| | 1,000 |
| | 1,000 |
|
Pepco | $ | 0.01 |
| | 200,000,000 |
| | 100 |
| | 100 |
| $ | 0.01 |
| | 200,000,000 |
| | 100 |
| | 100 |
|
DPL | $ | 2.25 |
| | 1,000 |
| | 1,000 |
| | 1,000 |
| $ | 2.25 |
| | 1,000 |
| | 1,000 |
| | 1,000 |
|
ACE | $ | 3.00 |
| | 25,000,000 |
| | 8,546,017 |
| | 8,546,017 |
| $ | 3.00 |
| | 25,000,000 |
| | 8,546,017 |
| | 8,546,017 |
|
ComEd had 60,58460,285 and 72,85960,584 warrants outstanding to purchase ComEd common stock at December 31, 20172018 and 2016,2017, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2018 and 2017, 20,095 and 2016, 20,195 and 24,286 shares of common stock, respectively, were reserved for the conversion of warrants.
Equity Securities Offering
In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. The net proceeds were used to fund the merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method.
Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. On June 1, 2017, Exelon settled the forward
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
purchase contract, which was a component of the June 2014 equity units, through the issuance of Exelon common stock from treasury stock. See Note 13 — Debt and Credit Agreements for furtheradditional information on the equity units.
Share Repurchases
Share Repurchase Programs
There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the previous share repurchase programs, 2 million and 35 million shares of common stock were held as treasury stock with a historical cost of $123 million and $2.3 billion at December 31, 20172018 and 2016, respectively.2017. During 2017, Exelon issued approximately 33 million shares of Exelon common stock from treasury stock in order to settle the forward purchase contract, which was a component of the June 2014 equity units discussed above. During 20162018, 2017, and 2015,2016 Exelon had no common stock repurchases.
Preferred and Preference Securities of Subsidiaries
At December 31, 20172018 and 2016,2017, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 20172018 and 2016,2017, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.
BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.
20.19. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2017,2018, there were approximately 1311 million shares authorized for issuance under the LTIP. For the years ended December 31, 2018, 2017 2016 and 2015,2016, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
ComEd, PECO, BGE and PHI grant cash awards. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.
In connection with the acquisition of PHI in March 2016, PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the years ended December 31, 2018, 2017 2016 and 2015,2016, there were no significant modifications to the granted stock based awards.
The following tables present the stock-based compensation expense included in Exelon's and PHI’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2018, 2017 2016 and 20152016 and PHI's predecessor periodsperiod January 1, 2016 to March 23, 2016 and the year ended December 31, 2015:2016:
| | Exelon | Year Ended December 31, | Year Ended December 31, |
Components of Stock-Based Compensation Expense | 2017 | | 2016(a) | | 2015 | 2018 | | 2017 | | 2016(a) |
Performance share awards | $ | 107 |
| | $ | 93 |
| | $ | 41 |
| $ | 143 |
| | $ | 107 |
| | $ | 93 |
|
Restricted stock units | 77 |
| | 75 |
| | 71 |
| 57 |
| | 77 |
| | 75 |
|
Stock options | — |
| | — |
| | 1 |
| — |
| | — |
| | — |
|
Other stock-based awards | 7 |
| | 7 |
| | 6 |
| 8 |
| | 7 |
| | 7 |
|
Total stock-based compensation expense included in operating and maintenance expense | 191 |
| | 175 |
| | 119 |
| 208 |
| | 191 |
| | 175 |
|
Income tax benefit | (74 | ) | | (68 | ) | | (46 | ) | (54 | ) | | (74 | ) | | (68 | ) |
Total after-tax stock-based compensation expense | $ | 117 |
| | $ | 107 |
| | $ | 73 |
| $ | 154 |
| | $ | 117 |
| | $ | 107 |
|
__________
| |
(a) | 2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016. |
PHI
|
| | | | | | | |
| Predecessor |
| January 1 to March 23, | | Year Ended December 31, |
Components of Stock-Based Compensation Expense | 2016 | | 2015 |
Time-based restricted stock units | $ | 2 |
| | $ | 7 |
|
Performance-based restricted stock units | 1 |
| | 5 |
|
Time-based restricted stock awards | — |
| | 1 |
|
Total stock-based compensation expense included in operating and maintenance expense | 3 |
| | 13 |
|
Income tax benefit | (1 | ) | | (5 | ) |
Total after-tax stock-based compensation expense | $ | 2 |
| | $ | 8 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
|
| | | |
| Predecessor |
| January 1 to March 23, |
Components of Stock-Based Compensation Expense | 2016 |
Time-based restricted stock units | $ | 2 |
|
Performance-based restricted stock units | 1 |
|
Time-based restricted stock awards | — |
|
Total stock-based compensation expense included in operating and maintenance expense | 3 |
|
Income tax benefit | (1 | ) |
Total after-tax stock-based compensation expense | $ | 2 |
|
The following tables present the Registrants' stock-based compensation expense (pre-tax) for the years ended December 31, 2018, 2017 2016 and 2015,2016, as well as for the PHI predecessor periodsperiod January 1, 2016 to March 23, 2016 and the year ended December 31, 2015:2016:
| | | Year Ended December 31, | Year Ended December 31, |
Subsidiaries | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Exelon | $ | 191 |
| | $ | 175 |
| | $ | 119 |
| $ | 208 |
| | $ | 191 |
| | $ | 175 |
|
Generation | 88 |
| | 78 |
| | 64 |
| 77 |
| | 88 |
| | 78 |
|
ComEd | 7 |
| | 8 |
| | 6 |
| 8 |
| | 7 |
| | 8 |
|
PECO | 3 |
| | 3 |
| | 3 |
| 5 |
| | 3 |
| | 3 |
|
BGE | 1 |
| | 1 |
| | 3 |
| 3 |
| | 1 |
| | 1 |
|
BSC(a) | 88 |
| | 81 |
| | 43 |
| 111 |
| | 88 |
| | 81 |
|
PHI Successor(b)(c) | 4 |
| | 4 |
| | — |
| 4 |
| | 4 |
| | 4 |
|
|
| | | | | | | |
| Predecessor |
| January 1 to March 23, | | For the Year Ended December 31, |
| 2016 | | 2015 |
PHI | $ | 3 |
| | $ | 13 |
|
|
| | | |
| Predecessor |
| January 1 to March 23, |
| 2016 |
PHI | $ | 3 |
|
__________
| |
(a) | These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above. |
| |
(b) | Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 20172018 and 20162017 was not material. |
| |
(c) | These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations. |
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2018, 2017 2016 and 20152016 for Exelon or PHI, or for PHI during the predecessor period January 1, 2016 to March 23, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon and PHI receivereceives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon and PHI recognizerecognizes the tax benefit related to compensation costs. The following tables present information regarding Exelon’s and PHI's tax benefits for the years ended December 31, 2018, 2017 2016 and 2015 and PHI's predecessor periods January 1, 2016 to March 23, 2016 and the year ended December 31, 2015:2016.
|
| | | | | | | | |
Exelon | Year Ended December 31, |
| 2017 | | 2016 | | 2015 |
Realized tax benefit when exercised/distributed: | | | | | |
Restricted stock units | 35 |
| | 27 |
| | 30 |
|
Performance share awards | 29 |
| | 18 |
| | 18 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
|
| | | | | | | |
| Predecessor |
| January 1 to March 23, | | For the Year Ended December 31, |
| 2016 | | 2015 |
Realized tax benefit when exercised/distributed: | | | |
Time-based restricted stock units | $ | — |
| | $ | 2 |
|
Performance-based restricted stock units | — |
| | 5 |
|
|
| | | | | | | | |
Exelon | Year Ended December 31, |
| 2018 | | 2017 | | 2016 |
Realized tax benefit when exercised/distributed: | | | | | |
Restricted stock units | 28 |
| | 35 |
| | 27 |
|
Performance share awards | 16 |
| | 29 |
| | 18 |
|
Stock Options
Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2018, 2017 2016 or 2015.and 2016. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years and all stock options will expire no later than ten years from the date of grant.
The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.
The following table presents information with respect to stock option activity for the year ended December 31, 2017:2018:
| | | Shares | | Weighted Average Exercise Price (per share) | | Weighted Average Remaining Contractual Life (years) | | Aggregate Intrinsic Value | Shares | | Weighted Average Exercise Price (per share) | | Weighted Average Remaining Contractual Life (years) | | Aggregate Intrinsic Value |
Balance of shares outstanding at December 31, 2016 | 12,531,591 |
| | $ | 46.23 |
| | 3.50 | | $ | 13 |
| |
Balance of shares outstanding at December 31, 2017 | | 6,723,611 |
| | $ | 47.69 |
| | 2.65 | | $ | 7 |
|
Options exercised | (3,093,156 | ) | | 34.69 |
| | | (1,522,952 | ) | | 36.54 |
| | |
Options forfeited | — |
| | — |
| | | — |
| | — |
| | |
Options expired | (2,714,824 | ) | | 55.78 |
| | | (1,173,007 | ) | | 74.99 |
| | |
Balance of shares outstanding at December 31, 2017 | 6,723,611 |
| | $ | 47.69 |
| | 2.65 | | $ | 7 |
| |
Exercisable at December 31, 2017(a) | 6,723,611 |
| | $ | 47.69 |
| | 2.65 | | $ | 7 |
| |
Balance of shares outstanding at December 31, 2018 | | 4,027,652 |
| | $ | 43.95 |
| | 2.90 | | $ | 14 |
|
Exercisable at December 31, 2018 (a) | | 4,027,652 |
| | $ | 43.95 |
| | 2.90 | | $ | 14 |
|
__________
| |
(a) | Includes stock options issued to retirement eligible employees. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | | Year Ended December 31, | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Intrinsic value(a) | $ | 15 |
| | $ | 11 |
| | $ | — |
| $ | 12 |
| | $ | 15 |
| | $ | 11 |
|
Cash received for exercise price | 107 |
| | 19 |
| | — |
| 56 |
| | 107 |
| | 19 |
|
__________
| |
(a) | The difference between the market value on the date of exercise and the option exercise price. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2016, all stock options were vested and at December 31, 20172018 there were no unrecognized compensation costs related to nonvested stock options.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2017:2018:
Exelon
| | | Shares | | Weighted Average Grant Date Fair Value (per share) | Shares | | Weighted Average Grant Date Fair Value (per share) |
Nonvested at December 31, 2016(a)(c) | 3,824,416 |
| | $ | 30.49 |
| |
Nonvested at December 31, 2017(a) | | 3,389,503 |
| | $ | 32.24 |
|
Granted | 2,266,199 |
| | 34.98 |
| 1,321,988 |
| | 38.60 |
|
Vested | (1,736,965 | ) | | 30.98 |
| (1,845,300 | ) | | 32.03 |
|
Forfeited | (92,938 | ) | | 33.12 |
| (65,046 | ) | | 32.96 |
|
Undistributed vested awards (b) | (871,209 | ) | | 34.09 |
| (507,804 | ) | | 36.76 |
|
Nonvested at December 31, 2017(a) | 3,389,503 |
| | $ | 32.24 |
| |
Nonvested at December 31, 2018(a) | | 2,293,341 |
| | $ | 35.06 |
|
__________
| |
(a) | Excludes 1,488,3831,131,487 and 1,319,3721,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 20172018 and 2016,2017, respectively, as they are fully vested. |
| |
(b) | Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2017. |
| |
(c) | 2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.2018. |
For Exelon, the weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2018, 2017 and 2016 was $38.60, $34.98 and 2015 was $34.98, $28.14, and $36.55, respectively. At December 31, 20172018 and 2016,2017, Exelon had obligations related to outstanding restricted stock units not yet settled of $108$83 million and $101$108 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2018, 2017 and 2016, and 2015, Exelon
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
settled restricted stock units with fair value totaling $106 million, $88 million $68 million and $75$68 million, respectively. At December 31, 2017, $512018, $38 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 1.72.5 years.
For PHI, the weighted average grant date fair value (per share) of time-based restricted stock units granted for the year ended December 31, 2015 was $27.40 and for performance-based restricted stock units was $26.08 for the same period. For the year ended December 31, 2015, PHI settled time-based restricted stock units with fair value totaling $6 million and settled performance-based restricted stock units with fair value totaling $15 million, for the same period. There were no settled restricted stock units for the predecessor period January 1, 2016 to March 23, 2016.
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Effective January 2017 for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.
In 2016 and prior, for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2017:2018:
Exelon
| | | Shares | | Weighted Average Grant Date Fair Value (per share) | Shares | | Weighted Average Grant Date Fair Value (per share) |
Nonvested at December 31, 2016(a)(c) | 3,116,261 |
| | $ | 30.77 |
| |
Nonvested at December 31, 2017(a) | | 2,956,966 |
| | $ | 32.65 |
|
Granted | 1,632,186 |
| | 35.00 |
| 1,637,542 |
| | 38.15 |
|
Change in performance | 545,793 |
| | 30.97 |
| 1,348,029 |
| | 30.66 |
|
Vested | (1,111,751 | ) | | 29.11 |
| (848,574 | ) | | 36.26 |
|
Forfeited | (18,034 | ) | | 33.74 |
| (50,467 | ) | | 36.24 |
|
Undistributed vested awards (b) | (1,207,489 | ) | | 33.46 |
| (1,640,268 | ) | | 33.38 |
|
Nonvested at December 31, 2017(a) | 2,956,966 |
| | $ | 32.65 |
| |
Nonvested at December 31, 2018(a) | | 3,403,228 |
| | $ | 33.13 |
|
__________
| |
(a) | Excludes 2,723,4403,586,259 and 2,443,4092,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 20172018 and 2016,2017, respectively, as they are fully vested. |
| |
(b) | Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2017. |
| |
(c) | 2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.2018. |
The following table summarizes the weighted average grant date fair value and the fair value of performance share awards granted and settled for the years ended December 31, 20172018, 20162017 and 2015:2016:
| | | Year Ended December 31, | Year Ended December 31, |
| 2017(a) | | 2016 | | 2015 | 2018(a) | | 2017 | | 2016 |
Weighted average grant date fair value (per share) | $ | 35.00 |
| | $ | 28.85 |
| | $ | 35.88 |
| $ | 38.15 |
| | $ | 35.00 |
| | $ | 28.85 |
|
Fair value of performance shares settled | 72 |
| | 45 |
| | 46 |
| 61 |
| | 72 |
| | 45 |
|
Fair value of performance shares settled in cash | 56 |
| | 28 |
| | 29 |
| 49 |
| | 56 |
| | 28 |
|
__________
| |
(a) | As of December 31, 2017, $412018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.51.7 years. |
For PHI, the weighted average grant date fair value (per share) of performance-based restricted stock awards was $26.10 for the year ended December 31, 2015.2016. There were no time-based restricted stock awards granted for the year ended December 31, 2015.2016. There were no time-based share settlements or performance-based share settlements for the year-ended December 31, 20152016 or the predecessor period January 1, 2016 to March 23, 2016.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Current liabilities(a) | $ | 57 |
| | $ | 49 |
| $ | 135 |
| | $ | 57 |
|
Deferred credits and other liabilities(b) | 100 |
| | 52 |
| 109 |
| | 100 |
|
Common stock | 26 |
| | 40 |
| 26 |
| | 26 |
|
Total | $ | 183 |
| | $ | 141 |
| $ | 270 |
| | $ | 183 |
|
__________
| |
(a) | Represents the current liability related to performance share awards expected to be settled in cash. |
| |
(b) | Represents the long-term liability related to performance share awards expected to be settled in cash. |
21.20. Earnings Per Share (Exelon)
Basic earnings per share is computed by dividing net income attributable to common stockholders by the weighted average number of common shares outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average number of common shares outstanding, including the effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share awards and restricted stock awards are fully vested under the treasury stock method.
The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:
| | | Year Ended December 31, | Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Net income attributable to common shareholders | $ | 3,770 |
|
| $ | 1,134 |
|
| $ | 2,269 |
| $ | 2,010 |
|
| $ | 3,786 |
|
| $ | 1,121 |
|
Weighted average common shares outstanding — basic | 947 |
|
| 924 |
|
| 890 |
| 967 |
|
| 947 |
|
| 924 |
|
Assumed exercise and/or distributions of stock-based awards | 2 |
| | 3 |
| | 3 |
| 2 |
| | 2 |
| | 3 |
|
Weighted average common shares outstanding — diluted | 949 |
|
| 927 |
|
| 893 |
| 969 |
|
| 949 |
|
| 927 |
|
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 3 million in 2018, 8 million in 2017, and 12 million in 2016, and 16 million in 2015.2016. There were no equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the years ended December 31, 2018, 2017, and 2016. 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 3 million for the year ended 2015. Refer toSee Note 1918 — Shareholders' Equity for furtheradditional information regarding the equity units and equity forward units.
On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017 triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method. Refer toSee Note 1918 — Shareholders' Equity for furtheradditional information regarding share repurchases.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
22. 21. Changes in Accumulated Other Comprehensive Income (Exelon, Generation PECO and PHI)PECO)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 20172018 and 2016:2017:
| | For the Year Ended December 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 | |
For the Year Ended December 31, 2018 | | Gains and (Losses) on Cash Flow Hedges |
| Unrealized Gains and (losses) on Marketable Securities |
| Pension and Non-Pension Postretirement Benefit Plan Items |
| Foreign Currency Items |
| AOCI of Investments Unconsolidated Affiliates |
| Total |
Exelon(a) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Beginning balance | $ | (17 | ) | | $ | 4 |
| | $ | (2,610 | ) | | $ | (30 | ) | | $ | (7 | ) | | $ | (2,660 | ) | $ | (14 | ) | | $ | 10 |
| | $ | (2,998 | ) | | $ | (23 | ) | | $ | (1 | ) | | $ | (3,026 | ) |
OCI before reclassifications | (1 | ) | | 6 |
| | 11 |
| | 7 |
| | 6 |
| | 29 |
| 11 |
| | — |
| | (143 | ) | | (10 | ) | | 1 |
| | (141 | ) |
Amounts reclassified from AOCI(b) | 4 |
| | — |
| | 140 |
| | — |
| | — |
| | 144 |
| 1 |
| | — |
| | 181 |
| | — |
| | — |
| | 182 |
|
Net current-period OCI | 3 |
|
| 6 |
|
| 151 |
|
| 7 |
|
| 6 |
|
| 173 |
| 12 |
|
| — |
|
| 38 |
|
| (10 | ) |
| 1 |
|
| 41 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | | — |
| | (10 | ) | | — |
| | — |
| | — |
| | (10 | ) |
Ending balance | $ | (14 | ) |
| $ | 10 |
|
| $ | (2,459 | ) |
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (2,487 | ) | $ | (2 | ) |
| $ | — |
|
| $ | (2,960 | ) |
| $ | (33 | ) |
| $ | — |
|
| $ | (2,995 | ) |
Generation(a) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Beginning balance | $ | (19 | ) | | $ | 2 |
| | $ | — |
| | $ | (30 | ) | | $ | (7 | ) | | $ | (54 | ) | $ | (16 | ) | | $ | 3 |
| | $ | — |
| | $ | (23 | ) | | $ | (1 | ) | | $ | (37 | ) |
OCI before reclassifications | (1 | ) | | 1 |
| | — |
| | 7 |
| | 6 |
| | 13 |
| 11 |
| | — |
| | — |
| | (10 | ) | | — |
| | 1 |
|
Amounts reclassified from AOCI(b) | 4 |
| | — |
| | — |
| | — |
| | — |
| | 4 |
| 1 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
|
Net current-period OCI | 3 |
|
| 1 |
|
| — |
|
| 7 |
|
| 6 |
|
| 17 |
| 12 |
|
| — |
|
| — |
|
| (10 | ) |
| — |
|
| 2 |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | | — |
| | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
Ending balance | $ | (16 | ) |
| $ | 3 |
|
| $ | — |
|
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (37 | ) | $ | (4 | ) |
| $ | — |
|
| $ | — |
|
| $ | (33 | ) |
| $ | (1 | ) |
| $ | (38 | ) |
PECO(a) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Beginning balance | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| $ | — |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net current-period OCI | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard(c) | | — |
| | (1 | ) | | — |
| | — |
| | — |
| | (1 | ) |
Ending balance | $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | For the Year Ended December 31, 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 | |
For the Year Ended December 31, 2017 | | Gains and (Losses) on Cash Flow Hedges | | Unrealized Gains on Marketable Securities | | Pension and Non-Pension Postretirement Benefit Plan items | | Foreign Currency Items | | AOCI of Investments Unconsolidated Affiliates | | Total |
Exelon(a) | | | | | | | | | | | | | | | | | | | | | | |
Beginning balance | $ | (19 | ) |
| $ | 3 |
|
| $ | (2,565 | ) |
| $ | (40 | ) |
| $ | (3 | ) | | $ | (2,624 | ) | $ | (17 | ) |
| $ | 4 |
|
| $ | (2,610 | ) |
| $ | (30 | ) |
| $ | (7 | ) | | $ | (2,660 | ) |
OCI before reclassifications | (6 | ) |
| 1 |
|
| (182 | ) |
| 5 |
|
| (4 | ) | | (186 | ) | (1 | ) |
| 6 |
|
| 11 |
|
| 7 |
|
| 6 |
| | 29 |
|
Amounts reclassified from AOCI(b) | 8 |
|
| — |
|
| 137 |
|
| 5 |
|
| — |
| | 150 |
| 4 |
|
| — |
|
| 140 |
|
| — |
|
| — |
| | 144 |
|
Net current-period OCI | 2 |
|
| 1 |
|
| (45 | ) |
| 10 |
|
| (4 | ) |
| (36 | ) | 3 |
|
| 6 |
|
| 151 |
|
| 7 |
|
| 6 |
|
| 173 |
|
Impact of adoption of Reclassification of Certain Tax Effects from AOCI(d) | | — |
| | — |
| | (539 | ) | | — |
| | — |
| | (539 | ) |
Ending balance | $ | (17 | ) |
| $ | 4 |
|
| $ | (2,610 | ) |
| $ | (30 | ) |
| $ | (7 | ) |
| $ | (2,660 | ) | $ | (14 | ) |
| $ | 10 |
|
| $ | (2,998 | ) |
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (3,026 | ) |
Generation(a) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Beginning balance | $ | (21 | ) |
| $ | 1 |
|
| $ | — |
|
| $ | (40 | ) |
| $ | (3 | ) | | $ | (63 | ) | $ | (19 | ) |
| $ | 2 |
|
| $ | — |
|
| $ | (30 | ) |
| $ | (7 | ) | | $ | (54 | ) |
OCI before reclassifications | (6 | ) |
| 1 |
|
| — |
|
| 5 |
|
| (4 | ) | | (4 | ) | (1 | ) |
| 1 |
|
| — |
|
| 7 |
|
| 6 |
| | 13 |
|
Amounts reclassified from AOCI(b) | 8 |
|
| — |
|
| — |
|
| 5 |
|
| — |
| | 13 |
| 4 |
|
| — |
|
| — |
|
| — |
|
| — |
| | 4 |
|
Net current-period OCI | 2 |
|
| 1 |
|
| — |
|
| 10 |
|
| (4 | ) |
| 9 |
| 3 |
|
| 1 |
|
| — |
|
| 7 |
|
| 6 |
|
| 17 |
|
Ending balance | $ | (19 | ) |
| $ | 2 |
|
| $ | — |
|
| $ | (30 | ) |
| $ | (7 | ) |
| $ | (54 | ) | $ | (16 | ) |
| $ | 3 |
|
| $ | — |
|
| $ | (23 | ) |
| $ | (1 | ) |
| $ | (37 | ) |
PECO(a) |
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
| |
|
Beginning balance | $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
| | $ | 1 |
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
| | $ | 1 |
|
OCI before reclassifications | — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
Amounts reclassified from AOCI(b) | — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
Net current-period OCI | — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Ending balance | $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
| $ | — |
|
| $ | 1 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 1 |
|
PHI Predecessor(a) | | | | | | | | | | | | |
Beginning balance January 1, 2016 | $ | (8 | ) | | $ | — |
| | $ | (28 | ) | | $ | — |
| | $ | — |
| | $ | (36 | ) | |
OCI before reclassifications | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Amounts reclassified from AOCI(b) | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| |
Net current-period OCI | — |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| |
Ending balance March 23, 2016(c) | $ | (8 | ) | | $ | — |
| | $ | (27 | ) | | $ | — |
| | $ | — |
| | $ | (35 | ) | |
__________
| |
(a) | All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI. |
| |
(b) | See next tables for details about these reclassifications. |
| |
(c) | As a resultExelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million, $3 million and $1 million for Exelon, Generation and PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies for additional information. |
| |
(d) | Exelon early adopted the PHI Merger, the PHI predecessor balances at March 23, 2016 were reducednew standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to zero on March 24, 2016 dueExelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to purchase accounting adjustments applied to PHI.deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 20172018 and 2016.2017. The following tables present amounts reclassified out of AOCI to Net income for Exelon Generation and PHIGeneration during the years ended December 31, 20172018 and 2016:2017:
For the Year Ended December 31, 20172018
|
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | | | | |
| | Exelon | | Generation | | |
Gains and (losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | (5 | ) | | $ | (5 | ) | | Interest expense |
Total before tax | | (5 | ) |
| (5 | ) | | |
Tax benefit | | 1 |
| | 1 |
| | |
Net of tax | | $ | (4 | ) |
| $ | (4 | ) | | Comprehensive income |
| | | | | | |
Amortization of pension and other postretirement benefit plan items |
Prior service costs(b) | | $ | 92 |
| | $ | — |
| | |
Actuarial losses(b) | | (324 | ) | | — |
| | |
Total before tax | | (232 | ) |
| — |
| | |
Tax benefit | | 92 |
| | — |
| | |
Net of tax | | $ | (140 | ) |
| $ | — |
| | Comprehensive Income |
| | | | | | |
Total Reclassifications | | $ | (144 | ) |
| $ | (4 | ) | | Comprehensive income |
|
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | Exelon | | Generation | | |
Gains (Losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | (1 | ) | | $ | (1 | ) | | Interest expense |
| | (1 | ) |
| (1 | ) | | Total before tax |
| | — |
| | — |
| | Tax benefit |
| | $ | (1 | ) |
| $ | (1 | ) | | Net of tax |
| | | | | | |
Amortization of pension and other postretirement benefit plan items |
Prior service costs(b) | | $ | 90 |
| | $ | — |
| | |
Actuarial losses(b) | | (333 | ) | | — |
| | |
| | (243 | ) |
| — |
| | Total before tax |
| | 62 |
| | — |
| | Tax benefit |
| | $ | (181 | ) |
| $ | — |
| | Net of tax |
| | | | | | |
Total Reclassifications | | $ | (182 | ) |
| $ | (1 | ) | | Net of tax |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the Year Ended December 31, 20162017
|
| | | | | | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | | | | | Predecessor | | |
| | | | | | January 1, 2016 to March 23, 2016 | | |
| | Exelon | | Generation | | PHI | | |
Loss on cash flow hedges | | | | | | | | |
Other cash flow hedges | | $ | (13 | ) | | $ | (13 | ) | | $ | — |
| | Interest expense |
Total before tax | | (13 | ) |
| (13 | ) |
| — |
| | |
Tax benefit | | 5 |
| | 5 |
| | — |
| | |
Net of tax | | $ | (8 | ) |
| $ | (8 | ) |
| $ | — |
| | Comprehensive income |
| | | | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | | | |
Prior service costs(b) | | $ | 78 |
| | $ | — |
| | $ | — |
| | |
Actuarial losses(b) | | (302 | ) | | — |
| | (1 | ) | | |
Total before tax | | (224 | ) |
| — |
|
| (1 | ) | | |
Tax benefit | | 87 |
| | — |
| | — |
| | |
Net of tax | | $ | (137 | ) |
| $ | — |
|
| $ | (1 | ) | | Comprehensive Income |
| | | | | | | | |
Losses on foreign currency translation | | | | | | | | |
Loss | | $ | (5 | ) | | $ | (5 | ) | | $ | — |
| | Other income and (deductions) |
Total before tax | | (5 | ) |
| (5 | ) |
| — |
| | |
Tax benefit | | — |
| | — |
| | — |
| | |
Net of tax | | $ | (5 | ) |
| $ | (5 | ) |
| $ | — |
| | |
Total Reclassifications | | $ | (150 | ) |
| $ | (13 | ) |
| $ | (1 | ) | | Comprehensive income |
|
| | | | | | | | | | |
Details about AOCI components | | Items reclassified out of AOCI(a) | | Affected line item in the Statement of Operations and Comprehensive Income |
| | Exelon | | Generation | | |
Gains (Losses) on cash flow hedges | | | | | | |
Other cash flow hedges | | $ | (5 | ) | | $ | (5 | ) | | Interest expense |
| | (5 | ) |
| (5 | ) |
| Total before tax |
| | 1 |
| | 1 |
| | Tax benefit |
| | $ | (4 | ) |
| $ | (4 | ) |
| Net of tax |
| | | | | | |
Amortization of pension and other postretirement benefit plan items | | | | | | |
Prior service costs(b) | | $ | 92 |
| | $ | — |
| | |
Actuarial losses(b) | | (324 | ) | | — |
| | |
| | (232 | ) |
| — |
|
| Total before tax |
| | 92 |
| | — |
| | Tax benefit |
| | $ | (140 | ) |
| $ | — |
|
| Net of tax |
| | | | | | |
Total Reclassifications | | $ | (144 | ) |
| $ | (4 | ) |
| Net of tax |
__________
| |
(a) | Amounts in parenthesis represent a decrease in net income. |
| |
(b) | This AOCI component is included in the computation of net periodic pension and OPEB cost (seecost. See Note 16 — Retirement Benefits for additional details).information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents income tax expense (benefit)benefit (expense) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2018, 2017 and 2016:
| | | For the Year Ended December 31, | For the Year Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Exelon | | | | | | | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | | | | |
Prior service benefit reclassified to periodic benefit cost | $ | 36 |
| | $ | 30 |
| | $ | 30 |
| $ | 24 |
| | $ | 36 |
| | $ | 30 |
|
Actuarial loss reclassified to periodic benefit cost | (128 | ) | | (118 | ) | | (140 | ) | (86 | ) | | (128 | ) | | (118 | ) |
Pension and non-pension postretirement benefit plans valuation adjustment | 13 |
| | 115 |
| | 62 |
| 50 |
| | 13 |
| | 115 |
|
Change in unrealized loss on cash flow hedges | (7 | ) | | — |
| | (6 | ) | |
Change in unrealized (loss)/gain on equity investments | (3 | ) | | 3 |
| | 1 |
| |
Change in unrealized loss on marketable securities
| (1 | ) | | — |
| | — |
| |
Change in unrealized gains on cash flow hedges | | (5 | ) | | (7 | ) | | — |
|
Change in unrealized gains (losses) on investments in unconsolidated affiliates | | — |
| | (3 | ) | | 3 |
|
Change in unrealized gains on marketable securities | | — |
| | (1 | ) | | — |
|
Total | $ | (90 | ) | | $ | 30 |
|
| $ | (53 | ) | $ | (17 | ) | | $ | (90 | ) |
| $ | 30 |
|
| | | | | | | | | | |
Generation | | | | | | | | | | |
Change in unrealized (loss)/gain on cash flow hedges | $ | (6 | ) | | $ | (2 | ) | | $ | 2 |
| |
Change in unrealized (loss)/gain on equity investments | (3 | ) | | 3 |
| | 1 |
| |
Change in unrealized loss marketable securities | (1 | ) | | — |
| | — |
| |
Change in unrealized gains on cash flow hedges | | $ | (4 | ) | | $ | (6 | ) | | $ | (2 | ) |
Change in unrealized gains (losses) on investments in unconsolidated affiliates | | (1 | ) | | (3 | ) | | 3 |
|
Change in unrealized gains on marketable securities | | — |
| | (1 | ) | | — |
|
Total | $ | (10 | ) | | $ | 1 |
|
| $ | 3 |
| $ | (5 | ) | | $ | (10 | ) |
| $ | 1 |
|
|
| | | | | | | |
| Predecessor |
| January 1 to March 23, | | For the Year Ended December 31, |
PHI | 2016 | | 2015 |
Pension and non-pension postretirement benefit plans: | | | |
Actuarial loss reclassified to periodic cost | $ | — |
| | $ | 6 |
|
23.22. Commitments and Contingencies (All Registrants)
Commitments
Constellation Merger Commitments
(Exelon and Generation). In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.
The direct investment includesincluded the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation’sGeneration's investment includesin leasehold improvements that are not expected to exceed $110totaled approximately $90 million. In addition, Generation entered into a 20-year operating lease as the primary lessee of the building.
The direct investment commitment also includesincluded $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285 - 300 MWs of new generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
in Maryland, which is expected to be completed within a period of 10 years. years after the merger. The MDPSC order contemplatescontemplated various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $457$458 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date and an additional 10 MW commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likelyis expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recorded a pre-tax$50 $50 millionloss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016. The remaining commitment is to be paid on or before January 15, 2023 unless the period is extended by consent of Exelon and the State of Maryland. As of December 31, 2018 and 2017, Exelon's and Generation's Consolidated Balance Sheets include a $50 million liability within Deferred credits and other liabilities for this remaining commitment.
Commercial Commitments
(All Registrants). Exelon’s commercial commitments as of December 31, 2017,2018, representing commitments potentially triggered by future events, were as follows:
| | | | | Expiration within | | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit (non-debt)(a) | $ | 1,226 |
| | $ | 1,056 |
| | $ | 154 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Letters of credit | | $ | 1,703 |
| | $ | 1,394 |
| | $ | 308 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(b)(a) | 1,381 |
| | 1,293 |
| | 66 |
| | 16 |
| | 6 |
| | — |
| | — |
| 1,402 |
| | 1,331 |
| | 33 |
| | 38 |
| | — |
| | — |
| | — |
|
Financing trust guarantees | 378 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 378 |
| 378 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 378 |
|
Guaranteed lease residual values(c)(b) | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 21 |
| 24 |
| | 3 |
| | 3 |
| | 2 |
| | 3 |
| | 3 |
| | 10 |
|
Total commercial commitments | $ | 3,006 |
| | $ | 2,349 |
| | $ | 220 |
| | $ | 32 |
| | $ | 6 |
| | $ | — |
| | $ | 399 |
| $ | 3,507 |
| | $ | 2,728 |
| | $ | 344 |
| | $ | 41 |
| | $ | 3 |
| | $ | 3 |
| | $ | 388 |
|
__________
| |
(a) | Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-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)(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $56$61 million, $16$19 million of which is a guarantee by Pepco, $23$26 million by DPL and $15$16 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Generation’s commercial commitments as of December 31, 2017,2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond |
Letters of credit (non-debt)(a) | $ | 1,177 |
| | $ | 1,007 |
| | $ | 154 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | �� |
|
Surety bonds | 1,209 |
| | 1,164 |
| | 45 |
| | — |
| | — |
| | — |
| | — |
|
Total commercial commitments | $ | 2,386 |
| | $ | 2,171 |
| | $ | 199 |
| | $ | 16 |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd’s commercial commitments as of December 31, 2017, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond |
Letters of credit (non-debt)(a) | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(b) | 10 |
| | 8 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
|
Financing trust guarantees | 200 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
|
Total commercial commitments | $ | 212 |
| | $ | 10 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 200 |
|
__________
| |
(a) | Letters of credit (non-debt)—ComEd maintains non-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. |
PECO’s commercial commitments as of December 31, 2017, representing commitments potentially triggered by future events, were as follows:
| | | | | Expiration within | | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit | | $ | 1,680 |
| | $ | 1,380 |
| | $ | 299 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | $ | 9 |
| | $ | 8 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| 1,220 |
| | 1,201 |
| | 19 |
| | — |
| | — |
| | — |
| | — |
|
Financing trust guarantees | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 178 |
| |
Total commercial commitments | $ | 187 |
| | $ | 8 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 178 |
| $ | 2,900 |
| | $ | 2,581 |
| | $ | 318 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
BGE’sComEd’s commercial commitments as of December 31, 2017,2018, representing commitments potentially triggered by future events, were as follows:
| | | | | Expiration within | | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit (non-debt)(a) | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| |
Letters of credit | | $ | 2 |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(b)(a) | 11 |
| | 10 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| 12 |
| | 10 |
| | — |
| | 2 |
| | — |
| | — |
| | — |
|
Financing trust guarantees | | 200 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 200 |
|
Total commercial commitments | $ | 13 |
| | $ | 12 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 214 |
| | $ | 12 |
| | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | — |
| | $ | 200 |
|
__________
| |
(a) | Letters of credit (non-debt)—BGE maintains non-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. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHIPECO’s commercial commitments (Successor) as of December 31, 2017,2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 9 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Financing trust guarantees | 178 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 178 |
|
Total commercial commitments | $ | 187 |
| | $ | 9 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 178 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
BGE’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond |
Surety bonds | $ | 63 |
| | $ | 48 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(a) | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 21 |
|
Total commercial commitments | $ | 84 |
|
| $ | 48 |
|
| $ | 15 |
|
| $ | — |
|
| $ | — |
|
| $ | — |
|
| $ | 21 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit | $ | 3 |
| | $ | 2 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | 17 |
| | 3 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
|
Total commercial commitments | $ | 20 |
| | $ | 5 |
| | $ | 15 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
PHI commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | $ | 41 |
| | $ | 41 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 24 |
| | 3 |
| | 3 |
| | 2 |
| | 3 |
| | 3 |
| | 10 |
|
Total commercial commitments | $ | 73 |
|
| $ | 44 |
|
| $ | 11 |
|
| $ | 2 |
|
| $ | 3 |
|
| $ | 3 |
|
| $ | 10 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $56$61 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco commercial commitments as of December 31, 2017,2018, representing commitments potentially triggered by future events, were as follows:
| | | | | Expiration within | | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond | Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Letters of credit | | $ | 8 |
| | $ | — |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Surety bonds(a) | $ | 54 |
| | $ | 41 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 33 |
| | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| 8 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 3 |
|
Total commercial commitments | $ | 60 |
| | $ | 41 |
| | $ | 13 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6 |
| $ | 49 |
| | $ | 34 |
| | $ | 9 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 3 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $19 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and Pepco believes the likelihood of payments being required under the guarantees is remote. |
DPL commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 5 |
| | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 10 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | 5 |
|
Total commercial commitments | $ | 15 |
| | $ | 6 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 1 |
| | $ | 5 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $26 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and DPL believes the likelihood of payments being required under the guarantees is remote. |
ACE commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2019 | | 2020 | | 2021 | | 2022 | | 2023 | | 2024 and beyond |
Surety bonds(a) | $ | 3 |
| | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 6 |
| | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 2 |
|
Total commercial commitments | $ | 9 |
| | $ | 4 |
| | $ | 1 |
| | $ | — |
| | $ | 1 |
| | $ | 1 |
| | $ | 2 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
DPL commercial commitments as of December 31, 2017, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond |
Surety bonds(a) | $ | 4 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(b) | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
|
Total commercial commitments | $ | 12 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 8 |
|
__________
| |
(a) | Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds. |
| |
(b) | Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $23 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHIACE believes the likelihood of payments being required under the guarantees is remote. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ACE commercial commitments as of December 31, 2017, representing commitments potentially triggered by future events, were as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Expiration within |
| Total | 2018 | | 2019 | | 2020 | | 2021 | | 2022 | | 2023 and beyond |
Surety bonds | $ | 4 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Guaranteed lease residual values(a) | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 6 |
|
Total commercial commitments | $ | 10 |
| | $ | 3 |
| | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
__________
| |
(a) | 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 $15 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote. |
Leases (All Registrants)
Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 20172018 were:
| | | | | | | | | | | | | Successor | | | | | | | Exelon(a)(b) | | Generation(a)(b) | | ComEd(a)(c) | | PECO(a)(c) | | BGE(a)(c)(d)(e) | | PHI(a) | | Pepco(a) | | DPL(a)(c) | | ACE(a) |
| Exelon(a) | | Generation(a) | | ComEd(a)(c) | | PECO(a)(c) | | BGE(a)(c)(d)(e) | | PHI(a) | | Pepco(a) | | DPL(a)(c) | | ACE(a) | |
2018 | $ | 188 |
| | $ | 74 |
| | $ | 7 |
| | $ | 5 |
| | $ | 34 |
| | $ | 56 |
| | $ | 8 |
| | $ | 20 |
| | $ | 9 |
| |
2019 | 129 |
| | 29 |
| | 6 |
| | 5 |
| | 34 |
| | 42 |
| | 7 |
| | 10 |
| | 8 |
| $ | 140 |
| | $ | 33 |
| | $ | 7 |
| | $ | 5 |
| | $ | 35 |
| | $ | 48 |
| | $ | 11 |
| | $ | 14 |
| | $ | 7 |
|
2020 | 147 |
| | 47 |
| | 4 |
| | 5 |
| | 34 |
| | 44 |
| | 6 |
| | 13 |
| | 8 |
| 149 |
| | 46 |
| | 5 |
| | 5 |
| | 35 |
| | 46 |
| | 10 |
| | 13 |
| | 6 |
|
2021 | 142 |
| | 48 |
| | 4 |
| | 5 |
| | 32 |
| | 40 |
| | 5 |
| | 12 |
| | 7 |
| 143 |
| | 46 |
| | 4 |
| | 5 |
| | 33 |
| | 43 |
| | 9 |
| | 12 |
| | 5 |
|
2022 | 119 |
| | 46 |
| | 2 |
| | 5 |
| | 17 |
| | 39 |
| | 4 |
| | 12 |
| | 6 |
| 126 |
| | 47 |
| | 4 |
| | 5 |
| | 18 |
| | 42 |
| | 8 |
| | 12 |
| | 5 |
|
2023 | | 97 |
| | 46 |
| | 3 |
| | 5 |
| | 3 |
| | 39 |
| | 8 |
| | 10 |
| | 4 |
|
Remaining years | 787 |
| | 573 |
| | — |
| | — |
| | 19 |
| | 194 |
| | 8 |
| | 54 |
| | 19 |
| 723 |
| | 545 |
| | — |
| | — |
| | 19 |
| | 159 |
| | 40 |
| | 35 |
| | 5 |
|
Total minimum future lease payments | $ | 1,512 |
| | $ | 817 |
| | $ | 23 |
| | $ | 25 |
| | $ | 170 |
| | $ | 415 |
| | $ | 38 |
| | $ | 121 |
| | $ | 57 |
| $ | 1,378 |
| | $ | 763 |
| | $ | 23 |
| | $ | 25 |
| | $ | 143 |
| | $ | 377 |
| | $ | 86 |
| | $ | 96 |
| | $ | 32 |
|
__________
| |
(a) | Includes amounts related to shared use land arrangements. |
| |
(b) | Excludes Generation’s contingent operating lease payments associated with contracted generation agreements. |
| |
(c) | Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd’s,ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2018—2022,2019 - 2023, was $2$3 million, $5 million, $1 million and $2$1 million respectively. Also includes amounts related to shared use land arrangements. |
| |
(d) | Includes all future lease payments on a 99-year real estate lease that expires in 2106. |
| |
(e) | The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $25 million, $26 million, $28 million, , $28 million and $14 million related to years 2018, 2019 2020, 2021and- 2022 , respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2018, 2017 2016 and 2015:2016:
| | For the Year Ended December 31, | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | Exelon | | Generation(a) | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE |
2018 | | $ | 670 |
| | $ | 558 |
| | $ | 7 |
| | $ | 10 |
| | $ | 35 |
| | $ | 10 |
| | $ | 13 |
| | $ | 8 |
|
2017 | $ | 709 |
| | $ | 578 |
| | $ | 9 |
| | $ | 9 |
| | $ | 32 |
| | $ | 11 |
| | $ | 16 |
| | $ | 14 |
| 709 |
| | 578 |
| | 9 |
| | 9 |
| | 32 |
| | 11 |
| | 16 |
| | 14 |
|
2016 | 777 |
| | 667 |
| | 15 |
| | 7 |
| | 22 |
| | 8 |
| | 15 |
| | 13 |
| 777 |
| | 667 |
| | 15 |
| | 7 |
| | 22 |
| | 8 |
| | 15 |
| | 13 |
|
2015 | 922 |
| | 851 |
| | 12 |
| | 9 |
| | 32 |
| | 7 |
| | 14 |
| | 13 |
| |
| | | Successor | | | Predecessor | Successor | | | Predecessor |
| For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | For the Year Ended December 31, 2015 | For the Year Ended December 31, 2018 | | For the Year Ended December 31, 2017 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
PHI | | | | | | | | | | | | | | | | |
Rental expense under operating leases | $ | 63 |
| | $ | 49 |
| | | $ | 12 |
| | $ | 60 |
| $ | 48 |
| | $ | 63 |
| | $ | 49 |
| | | $ | 12 |
|
__________
| |
(a) | Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $493 million, $508 million and $604 million during 2018, 2017 and $798 million during 2017, 2016, and 2015, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions. |
For information regarding capital lease obligations, see Note 13—Debt and Credit Agreements.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2017,2018, the current liability limit per incident is $13.4$14.1 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013.November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.0$13.6 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.8$3.1 billion, however any amounts payable under this secondary layer would be capped at $420$454 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4$14.1 billion limit for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
indemnity. See Note 2 — Variable Interest Entities for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is estimated to be $58 million for 2018, and was $60 million and $21 million for 2017 and 2016, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $21 million for 2016 and 2015.$31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $360$345 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial conditions, results of operations and cash flows.statements.
Spent Nuclear Fuel Obligation (Exelon and Generation)
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the yearyears ended December 31, 2018, 2017 and 2016,and2015, Generation did not incur any expense in SNF disposal fees. Until a new fee structure is in effect,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to be, delayed significantly.
The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devised a new strategy for long-term SNF management. The Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s SNF and high-level radioactive waste.
In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, Generation currently assumes the DOE will begin accepting SNF in 2030 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.
In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.
Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:
|
| | | | | | | |
| Total | | Net(a) |
Cumulative cash reimbursements(b)
| $ | 1,167 |
| | $ | 1,006 |
|
|
| | | | | | | |
| Total | | Net(a) |
Cumulative cash reimbursements(b)
| $ | 1,274 |
| | $ | 1,100 |
|
__________
| |
(a) | Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek. |
| |
(b) | Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 20172018 and 2016,2017, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:
| | | December 31, 2017 | | December 31, 2016 | December 31, 2018 |
| | December 31, 2017 |
|
DOE receivable - current(a) | $ | 94 |
| | $ | 109 |
| $ | 124 |
| | $ | 94 |
|
DOE receivable - noncurrent(b) | 15 |
| | 15 |
| 15 |
| | 15 |
|
Amounts owed to co-owners(a)(c) | (11 | ) | | (13 | ) | (17 | ) | | (11 | ) |
__________
| |
(a) | Recorded in Accounts receivable, other. |
| |
(b) | Recorded in Deferred debits and other assets, other |
| |
(c) | Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities. |
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. A prior owner of FitzPatrick also elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. The amounts were recorded at fair value. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on the FitzPatrick acquisition. As of December 31, 20172018 and 2016,2017, the SNF liability for the one-time fee with interest was $1,147$1,171 million and $1,024$1,147 million, respectively, which is included in Exelon's and Generation's Consolidated Balance Sheets. Interest for Exelon's and Generation's SNF liabilitiesaccrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2017,2018 was 1.149%.2.351% for the deferred amount transferred from ComEd and 2.217% for the deferred FitzPatrick amount. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.
Environmental Remediation Matters
General.General (All Registrants).The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial conditions, results of operationsstatements.
MGP Sites (Exelon and cash flows.the Utility Registrants).
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
MGP Sites
ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
ComEd has identified 42 sites, 1921 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 2321 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 2022.2023.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.
BGE has identified 13 former gas manufacturing or purification sites, 119 of which the remediation hashave been completedremediated and approved by the MDE and 24 that require some level of remediation and/or ongoing monitoring.activity. BGE has determined that a loss associated withexpects the majority of the remediation at these sites is probable and has recorded an estimated liability, which is included in the table below. However, it is reasonably possible that BGE’s cost of remediation for one of its sites could be up to $13 million.continue through at least 2019.
DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control. The remaining site is under study and the required cost at the site is not expected to be material.
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.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. See Note 34 — Regulatory Matters for additional information regarding the associated regulatory assets. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.
Combined NotesDuring the third quarter of 2018, the Utility Registrants completed a study of their future estimated environmental remediation requirements. The study resulted in a $48 million increase to Consolidated Financial Statements - (Continued)
(Dollarsthe environmental liability and related regulatory asset for ComEd. The increase was primarily due to a revised closure strategy at one site, which resulted in millions, except per share data unless otherwise noted)
an increase in the excavation area and depth of impacted soils from the site. The study did not result in a material change to the environmental liability for PECO, BGE, Pepco, DPL, and ACE.
As of December 31, 20172018 and 2016,2017, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
| | December 31, 2017 | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation | |
December 31, 2018 | | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation |
Exelon | $ | 466 |
| | $ | 315 |
| $ | 496 |
| | $ | 356 |
|
Generation | 117 |
| | — |
| 108 |
| | — |
|
ComEd | 285 |
| | 283 |
| 329 |
| | 327 |
|
PECO | 30 |
| | 28 |
| 27 |
| | 25 |
|
BGE | 5 |
| | 4 |
| 5 |
| | 4 |
|
PHI | 29 |
| | — |
| 27 |
| | — |
|
Pepco | 27 |
| | — |
| 25 |
| | — |
|
DPL | 1 |
| | — |
| 1 |
| | — |
|
ACE | 1 |
| | — |
| 1 |
| | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | |
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 | 30 |
| | 1 |
|
Pepco | 27 |
| | — |
|
DPL | 2 |
| | 1 |
|
ACE | 1 |
| | — |
|
During the third quarter of 2017, ComEd, PECO, BGE and DPL completed an annual study of their future estimated MGP remediation requirements. The study resulted in a $13 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively, and no change at BGE and DPL.
Solid and Hazardous Waste |
| | | | | | | |
December 31, 2017 | Total environmental investigation and remediation reserve | | Portion of total related to MGP investigation and remediation |
Exelon | $ | 466 |
| | $ | 315 |
|
Generation | 117 |
| | — |
|
ComEd | 285 |
| | 283 |
|
PECO | 30 |
| | 28 |
|
BGE | 5 |
| | 4 |
|
PHI | 29 |
| | — |
|
Pepco | 27 |
| | — |
|
DPL | 1 |
| | — |
|
ACE | 1 |
| | — |
|
Cotter Corporation. Corporation (Exelon and Generation).The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the draft final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s proposed remedy selection, as further discussed below. There are currently three PRPs
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing. As of December 31, 2016, Generation had previously recorded an estimated liability for its anticipated share of a landfill cover remedy, which at the time was estimated to cost approximately $90 million in total.
On February 1,September 27, 2018 the EPA announcedissued its ROD Amendment for the selection of the final remedy for the West Lake Landfill Superfund site. The ROD modifies the EPA’s previously proposed remedy involvingplan for partial excavation of the site with an enhanced landfill cover.radiological materials by reducing the depths of the excavation. The proposed remedy will be openROD also allows for public comment through March 22, 2018 and Generation currently expectsvariation in depths of excavation depending on radiological concentrations. The EPA estimates that athe ROD will be issued duringresult in a reduction of both radiological and non-radiological waste excavated, with corresponding reductions in the third quartercost and schedule for the remedy. The next step is the negotiation of 2018. Thereafter, the EPA will seek to enter into a Consent DecreeAgreement by the EPA with the PRPs to effectuateimplement the remedy, which Generation currently expects will occurROD, a process that is expected to be completed in late 2018 or early 2019.the first quarter of 2020. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $340$280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability as of December 31, 2017, included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost for the entire remediation effort. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the ultimate required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share recorded as of December 31, 2017, could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial conditions, results of operations and cash flows.statements.
On January 16, 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. TheIn September 2018, the PRPs have been provided with a draft statement of work that will form the basis ofagreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake to be approximately $20 millionmillion. Generation determined a loss associated with the RI/FS is probable and Generation has recorded a liability as of December 31, 2017, included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
or the extent to which, if any, remediation activities will be required and cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future results of operations and cash flows.financial statements.
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action, and the work is expected to bedisposed which was completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been employed by the adjacent landfill owner. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial conditions, results of operations and cash flows.statements.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs. The DOJ and the PRPs agreed to toll the statute of limitations until August 20182019 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possibleprobable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of the lawsuits as untimely, and that ruling is currentlywhich has been upheld on appeal. Pre-trial motionsCotter and discovery are proceeding in the remaining casesplaintiffs have engaged in settlement discussions pursuant to court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings and a pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation cannot estimate a range of loss, if any. As such, no liability has been recorded for these lawsuits.an immaterial liability.
Benning Road Site.Site (Exelon, Generation, PHI and Pepco).In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility 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. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by May 6, 2019.
Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After 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 Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco).Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, 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 the Maryland-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 Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting thereleased a draft remedial investigation report for public review and thatcomment. Pepco submitted written comments to the draft RI and participated in a feasibility study of potential remedies is being prepared. DOEE currently is working under a statutorily mandated datepublic hearing. Pepco continues outreach efforts as appropriate to complete the Record of Decision selecting the final remedy for the project by June 30, 2018. However, on January 11,agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the DOEE requested at a hearing of the District of Columbia Council Committeeextended the deadline for completion of the Environment that this statutory deadline be extendedRecord of Decision from June 30, 2018 until December 31, 2019 to reflect the time necessary to complete the investigation. A recommendation by the Committee to the DC Council is expected in the near future. The District of Columbia Council will make the final determination to extend the deadline.2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred,, Pepco cannot estimate the reasonably possible range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared by the agencies and is expected to be released in 2019, at which time Pepco will likely be in a better position to estimate the range of loss.
Conectiv Energy Wholesale Power Generation Sites.In July 2010, PHI soldaddition to the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy)activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment 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 remediatedetermine if any environmental contamination at eachnatural resources have been damaged as a result of the nine Conectiv Energy generating facility sites located in New Jersey. Undercontamination that is being remediated, and, if so, that a plan be developed by the termsfederal, state and local Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the sale, Calpine has assumed responsibility for performingcontaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the ISRA-required remediation and forsecond quarter of 2018, Pepco became aware that the payment of all related ISRA compliance costs up to $10 million. Predecessor PHI was 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 nine generating facility sites located in New JerseyTrustees are in the range of approximately $7 million to $18 million, and predecessor PHI recorded an estimated liability for its share of the estimated clean-up costs. Pursuant
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
to Exelon’s March 2016 acquisition of PHI, the Conectiv Energy legal entity was transferred to Generation and the liability for Predecessor PHI's share of the estimated clean- up costs was also transferred to Generation and is included in the table above as a liability of Generation. The responsibility to indemnify Calpine is shared by PHI and Generation.
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 Pepco right-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 salebeginning stages of this site, Pepco indicated its willingnessprocess that often takes many years beyond the remedial decision to investigate the extent of, and propose an appropriate closure plan to address, ash on the right-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.
complete. Pepco has determinedconcluded that a loss associated with this matterthe eventual NRD assessment is probable and has recorded an estimated liability, which is included inreasonably possible. Due to the table above. Pepco believes thatvery early stage of the costs incurred in this matter may be recoverable from NRG underassessment process it cannot reasonably estimate the 2000 sale agreement, but has not recorded an associated receivable for any potential recovery.range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims
Exelon (Exelon, Generation, ComEd and Generation.PECO). Generation maintains estimated liabilities for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 20172018 and 2016,2017, Generation had recorded estimated liabilities of approximately $78$79 million and $83$78 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2017,2018, approximately $21$24 million of this amount related to 230238 open claims presented to Generation, while the remaining $57$55 million 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 adjustments to the estimated liabilities are necessary.
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, 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 accrued for on a claim by claim basis. Those additional claims are taken into account in projecting estimated 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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
direct civil action against an employer for latent diseases, including asbestos-related diseases that fall outside the 25-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 the 25-year maximum time period for filing a Worker’s Compensation claim. As a result of this ruling, Exelon, Generation, and ComEd have not recorded an increase to the asbestos-related bodily injury liability as of December 31, 2017.
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 unfavorable impact on Exelon’s,Exelon's and Generation’s and PECO’s financial conditions, results of operations and cash flows.statements.
Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE)
(All Registrants).Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
The Federal Power Act declares it to be unlawful for any officerUnder applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or director of any public utility “to participate in the makingcurrent earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictionsACE may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowedcompanies can distribute to pay dividends sufficient to meet Exelon’s actual cash needs.Exelon.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock togetherhas agreed in connection with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. On May 1, 2013,financings arranged through PEC L.P. and PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. Additionally,Trust IV that PECO maywill not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.
BGE is subject to certain dividend restrictions established by the MDPSC. First,MDPSC that prohibit BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally,
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days beforeNo such a dividend is paid.event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissionsMDPSC and the BoardDCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissionsDPSC and the BoardMDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the BoardNJBPU or (b) ACE’sACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid it its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Conduit Lease with City of Baltimore
(Exelon and BGE). On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a decrease to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued as well as the settlement of prior year disputed fee true-up amounts.
Deere Wind Energy Assets
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 receive earn-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 sought to recover a $14 million earn-out payment associated with one such project, which was never completed. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. As a result, in the second quarter of 2016, Generation increased its accrued liability to $14 million. On January 17, 2017, Generation filed an appeal with the Delaware Supreme Court. On December 18, 2017, the Delaware Supreme Court reversed the Superior Court decision and entered final judgment in favor of Generation. As a result, in the fourth quarter of 2017, Generation reversed its previously established liability of $14 million.
City of Everett Tax Increment Financing Agreement (Exelon)
(Exelon and Generation).On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement)
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
relating to Mystic 8 & 9 on the grounds that the total investment in Mystic 8 & 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts Superior Court proceeding. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF Agreement in 2019, could be material to Generation’s results of operations and cash flows.financial statements.
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
See Note 14 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil-generating assets.
24.23. 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 years ended December 31, 2018, 2017 2016 and 2015.2016.
| | | For the year ended December 31, 2017 | For the year ended December 31, 2018 |
| | | | | | | | | | | Successor | | | | | | | | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Taxes other than income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 898 |
| | $ | 126 |
| | $ | 240 |
| | $ | 125 |
| | $ | 89 |
| | $ | 318 |
| | $ | 300 |
| | $ | 18 |
| | $ | — |
| $ | 919 |
| | $ | 114 |
| | $ | 243 |
| | $ | 131 |
| | $ | 94 |
| | $ | 337 |
| | $ | 316 |
| | $ | 21 |
| | $ | — |
|
Property | 545 |
| | 269 |
| | 28 |
| | 14 |
| | 132 |
| | 101 |
| | 62 |
| | 32 |
| | 3 |
| 557 |
| | 273 |
| | 30 |
| | 15 |
| | 143 |
| | 94 |
| | 58 |
| | 32 |
| | 3 |
|
Payroll | 230 |
| | 121 |
| | 26 |
| | 15 |
| | 15 |
| | 26 |
| | 6 |
| | 4 |
| | 2 |
| 247 |
| | 130 |
| | 27 |
| | 16 |
| | 17 |
| | 24 |
| | 5 |
| | 3 |
| | 2 |
|
Other | 58 |
| | 39 |
| | 2 |
| | — |
| | 4 |
| | 7 |
| | 3 |
| | 3 |
| | 1 |
| 60 |
| | 39 |
| | 11 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total taxes other than income | $ | 1,731 |
| | $ | 555 |
| | $ | 296 |
| | $ | 154 |
| | $ | 240 |
|
| $ | 452 |
| | $ | 371 |
|
| $ | 57 |
|
| $ | 6 |
| $ | 1,783 |
| | $ | 556 |
| | $ | 311 |
| | $ | 163 |
| | $ | 254 |
|
| $ | 455 |
| | $ | 379 |
|
| $ | 56 |
|
| $ | 5 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | For the year ended December 31, 2017 |
| For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Taxes other than income | Taxes other than income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 753 |
| | $ | 122 |
| | $ | 242 |
| | $ | 136 |
| | $ | 85 |
| | $ | 312 |
| | $ | 18 |
| | $ | — |
| | $ | 253 |
| | | $ | 78 |
| $ | 898 |
| | $ | 126 |
| | $ | 240 |
| | $ | 125 |
| | $ | 89 |
| | $ | 318 |
| | $ | 300 |
| | $ | 18 |
| | $ | — |
|
Property | 483 |
| | 246 |
| | 27 |
| | 13 |
| | 123 |
| | 53 |
| | 31 |
| | 3 |
| | 73 |
| | | 18 |
| 545 |
| | 269 |
| | 28 |
| | 14 |
| | 132 |
| | 101 |
| | 62 |
| | 32 |
| | 3 |
|
Payroll | 226 |
| | 117 |
| | 28 |
| | 15 |
| | 17 |
| | 8 |
| | 5 |
| | 3 |
| | 23 |
| | | 8 |
| 230 |
| | 121 |
| | 26 |
| | 15 |
| | 15 |
| | 26 |
| | 6 |
| | 4 |
| | 2 |
|
Other | 114 |
| | 21 |
| | (4 | ) | | — |
| | 4 |
| | 4 |
| | 1 |
| | 1 |
| | 5 |
| | | 1 |
| 58 |
| | 39 |
| | 2 |
| | — |
| | 4 |
| | 7 |
| | 3 |
| | 3 |
| | 1 |
|
Total taxes other than income | $ | 1,576 |
| | $ | 506 |
| | $ | 293 |
| | $ | 164 |
| | $ | 229 |
|
| $ | 377 |
|
| $ | 55 |
|
| $ | 7 |
| | $ | 354 |
| | | $ | 105 |
| $ | 1,731 |
| | $ | 555 |
| | $ | 296 |
| | $ | 154 |
| | $ | 240 |
|
| $ | 452 |
| | $ | 371 |
|
| $ | 57 |
|
| $ | 6 |
|
| | | For the year ended December 31, 2015 | | | | | | | | | | | | | | | | | Successor | | Predecessor |
| | | | | | | | | | | Predecessor | | | | | | | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | PHI |
Taxes other than income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Utility(a) | $ | 474 |
| | $ | 105 |
| | $ | 236 |
| | $ | 133 |
| | $ | 85 |
| | $ | 326 |
| | $ | 308 |
| | $ | 18 |
| | $ | — |
| $ | 753 |
| | $ | 122 |
| | $ | 242 |
| | $ | 136 |
| | $ | 85 |
| | $ | 312 |
| | $ | 18 |
| | $ | — |
| | $ | 253 |
| | $ | 78 |
|
Property | 407 |
| | 250 |
| | 27 |
| | 11 |
| | 119 |
| | 94 |
| | 57 |
| | 28 |
| | 3 |
| 483 |
| | 246 |
| | 27 |
| | 13 |
| | 123 |
| | 53 |
| | 31 |
| | 3 |
| | 73 |
| | 18 |
|
Payroll | 201 |
| | 118 |
| | 28 |
| | 14 |
| | 16 |
| | 27 |
| | 6 |
| | 4 |
| | 2 |
| 226 |
| | 117 |
| | 28 |
| | 15 |
| | 17 |
| | 8 |
| | 5 |
| | 3 |
| | 23 |
| | 8 |
|
Other | 118 |
| | 16 |
| | 5 |
| | 2 |
| | 4 |
| | 8 |
| | 5 |
| | 1 |
| | 2 |
| 114 |
| | 21 |
| | (4 | ) | | — |
| | 4 |
| | 4 |
| | 1 |
| | 1 |
| | 5 |
| | 1 |
|
Total taxes other than income | $ | 1,200 |
| | $ | 489 |
| | $ | 296 |
| | $ | 160 |
| | $ | 224 |
|
| $ | 455 |
|
| $ | 376 |
|
| $ | 51 |
|
| $ | 7 |
| $ | 1,576 |
| | $ | 506 |
| | $ | 293 |
| | $ | 164 |
| | $ | 229 |
|
| $ | 377 |
|
| $ | 55 |
|
| $ | 7 |
|
| $ | 354 |
| | $ | 105 |
|
__________
| |
(a) | Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | For the year ended December 31, 2017 | For the year ended December 31, 2018 |
| | | | | | | | | | | 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) | | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 488 |
| | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 506 |
| | $ | 506 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Non-regulatory agreement units | 209 |
| | 209 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 302 |
| | 302 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | | |
Net unrealized losses on NDT funds | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 455 |
| | 455 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (715 | ) | | (715 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-regulatory agreement units | 521 |
| | 521 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (483 | ) | | (483 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (10 | ) | | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (8 | ) | | (8 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (724 | ) | | (724 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Regulatory offset to NDT fund-related activities(b) | | 171 |
| | 171 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total decommissioning-related activities | 939 |
|
| 939 |
|
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| — |
| (227 | ) |
| (227 | ) |
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
| — |
|
Investment income | 8 |
| | 6 |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
| | — |
| | — |
| 43 |
| | 32 |
| | — |
| | 1 |
| | 1 |
| | 4 |
| | 2 |
| | 1 |
| | — |
|
Interest income (expense) related to uncertain income tax positions | 3 |
| | (1 | ) |
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| |
Penalty related to uncertain income tax positions(c) | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Interest income related to uncertain income tax positions | | 5 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
AFUDC—Equity | 73 |
| | — |
| | 12 |
| | 9 |
| | 16 |
| | 36 |
| | 23 |
| | 7 |
| | 6 |
| 69 |
| | — |
| | 19 |
| | 7 |
| | 18 |
| | 25 |
| | 22 |
| | 2 |
| | 1 |
|
Non-service net periodic benefit cost | | (47 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | 31 |
| | 4 |
| | 10 |
| | — |
| | — |
| | 16 |
| | 8 |
| | 7 |
| | 1 |
| 45 |
| | 16 |
| | 14 |
| | — |
| | — |
| | 14 |
| | 7 |
| | 7 |
| | 1 |
|
Other, net | $ | 1,056 |
|
| $ | 948 |
|
| $ | 22 |
|
| $ | 9 |
|
| $ | 16 |
| | $ | 54 |
|
| $ | 32 |
|
| $ | 14 |
|
| $ | 7 |
| $ | (112 | ) |
| $ | (178 | ) |
| $ | 33 |
|
| $ | 8 |
|
| $ | 19 |
| | $ | 43 |
|
| $ | 31 |
|
| $ | 10 |
|
| $ | 2 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | | | | | | | | Successor | | | Predecessor | For the year ended December 31, 2017 |
| For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 | | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Other, Net | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 237 |
| | $ | 237 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
| $ | 488 |
| | $ | 488 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Non-regulatory agreement units | 126 |
| | 126 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 209 |
| | 209 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized gains on decommissioning trust funds | | | | | | | | | | | | | | | | | | | | | |
Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | 216 |
| | 216 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 455 |
| | 455 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-regulatory agreement units | 194 |
| | 194 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 521 |
| | 521 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| (10 | ) | | (10 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | (372 | ) | | (372 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| |
Regulatory offset to NDT fund-related activities(b) | | (724 | ) | | (724 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total decommissioning-related activities | 400 |
|
| 400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
| | | — |
| 939 |
|
| 939 |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
|
| — |
|
| — |
|
Investment income (loss) | 17 |
| | 8 |
| | — |
| | (1 | ) | | 2 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | | — |
| |
Long-term lease income | 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| |
Investment income | | 8 |
| | 6 |
| | — |
| | — |
| | — |
| | 2 |
| | 1 |
| | — |
| | — |
|
Interest income (expense) related to uncertain income tax positions | 13 |
|
| — |
|
| — |
|
| — |
|
| — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | | — |
| 3 |
|
| (1 | ) |
| — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
|
Penalty related to uncertain income tax positions(c) | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| |
Benefit related to uncertain income tax positions(c) | | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
AFUDC—Equity | 64 |
| | — |
| | 14 |
| | 8 |
| | 19 |
| | 19 |
| | 5 |
| | 6 |
| | 23 |
| | | 7 |
| 73 |
| | — |
| | 12 |
| | 9 |
| | 16 |
| | 36 |
| | 23 |
| | 7 |
| | 6 |
|
Loss on debt extinguishment | (3 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| |
Non-service net periodic benefit cost | | (109 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | 24 |
| | (5 | ) | | 7 |
| | 1 |
| | — |
| | 15 |
| | 8 |
| | 2 |
| | 21 |
| | | (11 | ) | 31 |
| | 4 |
| | 10 |
| | — |
| | — |
| | 16 |
| | 8 |
| | 7 |
| | 1 |
|
Other, net | $ | 413 |
|
| $ | 401 |
|
| $ | (65 | ) |
| $ | 8 |
|
| $ | 21 |
|
| $ | 36 |
|
| $ | 13 |
|
| $ | 9 |
| | $ | 44 |
| | | $ | (4 | ) | $ | 947 |
|
| $ | 948 |
|
| $ | 22 |
|
| $ | 9 |
|
| $ | 16 |
|
| $ | 54 |
| | $ | 32 |
|
| $ | 14 |
|
| $ | 7 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | For the year ended December 31, 2015 | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | | | | | | | | | | Predecessor | | | | | | | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Other, Net | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Decommissioning-related activities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Net realized income on decommissioning trust funds(a) | | | | | | | | | | | | | | | | | | |
Net realized income on NDT funds(a) | | | | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | $ | 232 |
| | $ | 232 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 237 |
| | $ | 237 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | | $ | — |
|
Non-regulatory agreement units | 156 |
| | 156 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 126 |
| | 126 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Net unrealized losses on decommissioning trust funds | | | | | | | | | | | | | | | | | | |
Net unrealized gains on NDT funds | | | | | | | | | | | | | | | | | | | | | |
Regulatory agreement units | (282 | ) | | (282 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 216 |
| | 216 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Non-regulatory agreement units | (197 | ) | | (197 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 194 |
| | 194 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Net unrealized gains on pledged assets | | | | | | | | | | | | | | | | | | |
Net unrealized losses on pledged assets | | | | | | | | | | | | | | | | | | | | | |
Zion Station decommissioning | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| (1 | ) | | (1 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Regulatory offset to decommissioning trust fund-related activities(b) | 21 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Regulatory offset to NDT fund-related activities(b) | | (372 | ) | | (372 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total decommissioning-related activities | (63 | ) |
| (63 | ) |
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| 400 |
|
| 400 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
| | — |
| | | — |
|
Investment income (loss) | 8 |
| | 3 |
| | — |
| | (2 | ) | | 4 |
| | — |
| | — |
| | — |
| | — |
| 17 |
| | 8 |
| | — |
| | (1 | ) | | 2 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | | — |
|
Long-term lease income | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 4 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Interest income related to uncertain income tax positions | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | 34 |
| | 5 |
| | — |
| | — |
| |
Interest income (expense) related to uncertain income tax positions | | 13 |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | (1 | ) | | | — |
|
Penalty related to uncertain income tax positions(c) | | (106 | ) | | — |
| | (86 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
AFUDC—Equity | 24 |
| | — |
| | 5 |
| | 5 |
| | 14 |
| | 14 |
| | 12 |
| | 1 |
| | 1 |
| 64 |
| | — |
| | 14 |
| | 8 |
| | 19 |
| | 19 |
| | 5 |
| | 6 |
| | 23 |
| | | 7 |
|
Terminated interest rate swaps(d) | (26 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
PHI merger related debt exchange(e) | (22 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Non-service net periodic benefit cost | | (116 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Loss on debt extinguishment | | (3 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other | 17 |
| | (1 | ) | | 16 |
| | 2 |
| | — |
| | 40 |
| | 11 |
| | 9 |
| | 2 |
| 24 |
| | (5 | ) | | 7 |
| | 1 |
| | — |
| | 15 |
| | 8 |
| | 2 |
| | 21 |
| | | (11 | ) |
Other, net | $ | (46 | ) |
| $ | (60 | ) |
| $ | 21 |
|
| $ | 5 |
|
| $ | 18 |
|
| $ | 88 |
|
| $ | 28 |
|
| $ | 10 |
|
| $ | 3 |
| $ | 297 |
|
| $ | 401 |
|
| $ | (65 | ) |
| $ | 8 |
|
| $ | 21 |
|
| $ | 36 |
|
| $ | 13 |
|
| $ | 9 |
| | $ | 44 |
| | | $ | (4 | ) |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
| |
(a) | Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning trustNDT funds. |
| |
(b) | Includes the elimination of NDT fund activitydecommissioning-related activities for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for thosethese units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(c) | See Note 14—Income Taxes for discussion ofadditional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position. |
| |
(d) | In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten-year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon's Consolidated Statements of Operations and Comprehensive Income. |
| |
(e) | See Note 13—Debt and Credit Agreements and Note 4—Mergers, Acquisitions and Dispositions for additional information on the PHI merger related debt exchange. |
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 years ended December 31, 2018, 2017 2016 and 2015.2016.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | |
Property, plant and equipment | $ | 3,740 |
| | $ | 1,748 |
| | $ | 820 |
| | $ | 274 |
| | $ | 335 |
| | $ | 480 |
| | $ | 218 |
| | $ | 131 |
| | $ | 94 |
|
Regulatory assets | 555 |
| | — |
| | 120 |
| | 27 |
| | 148 |
| | 260 |
| | 167 |
| | 51 |
| | 42 |
|
Amortization of intangible assets, net | 58 |
| | 49 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(a) | 14 |
| | 14 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(b) | 1,115 |
| | 1,115 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(c) | 489 |
| | 489 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total depreciation, amortization and accretion | $ | 5,971 |
| | $ | 3,415 |
| | $ | 940 |
|
| $ | 301 |
| | $ | 483 |
|
| $ | 740 |
| | $ | 385 |
|
| $ | 182 |
|
| $ | 136 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | |
Property, plant and equipment | $ | 3,293 |
| | $ | 1,409 |
| | $ | 777 |
| | $ | 261 |
| | $ | 312 |
| | $ | 457 |
| | $ | 203 |
| | $ | 124 |
| | $ | 89 |
|
Regulatory assets | 478 |
| | — |
| | 73 |
| | 25 |
| | 161 |
| | 218 |
| | 118 |
| | 43 |
| | 57 |
|
Amortization of intangible assets, net | 57 |
| | 48 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of energy contract assets and liabilities(a) | 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Nuclear fuel(b) | 1,096 |
| | 1,096 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
ARO accretion(c) | 468 |
| | 468 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total depreciation, amortization and accretion | $ | 5,427 |
|
| $ | 3,056 |
|
| $ | 850 |
|
| $ | 286 |
|
| $ | 473 |
|
| $ | 675 |
| | $ | 321 |
|
| $ | 167 |
|
| $ | 146 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | |
Property, plant and equipment | $ | 3,477 |
| | $ | 1,835 |
| | $ | 708 |
| | $ | 244 |
| | $ | 299 |
| | $ | 175 |
| | $ | 110 |
| | $ | 82 |
| | $ | 325 |
| | | $ | 94 |
|
Regulatory assets | 407 |
| | — |
| | 67 |
| | 26 |
| | 124 |
| | 120 |
| | 47 |
| | 83 |
| | 190 |
| | | 58 |
|
Amortization of intangible assets, net | 52 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of energy contract assets and liabilities(a) | 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Nuclear fuel(b) | 1,159 |
| | 1,159 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
ARO accretion(c) | 446 |
| | 446 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total depreciation, amortization and accretion | $ | 5,576 |
|
| $ | 3,519 |
|
| $ | 775 |
|
| $ | 270 |
|
| $ | 423 |
|
| $ | 295 |
|
| $ | 157 |
|
| $ | 165 |
|
| $ | 515 |
| | | $ | 152 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | For the year ended December 31, 2015 | | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| | | | | | | | | | | | | | | | | Predecessor | For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Depreciation, amortization and accretion | | | | | | | | | | | | | | | | | | Depreciation, amortization and accretion | | | | | | | | | | | | | | | | |
Property, plant and equipment | $ | 2,227 |
| | $ | 1,007 |
| | $ | 635 |
| | $ | 240 |
| | $ | 289 |
| | $ | 164 |
| | $ | 103 |
| | $ | 76 |
| | $ | 392 |
| $ | 3,477 |
| | $ | 1,835 |
| | $ | 708 |
| | $ | 244 |
| | $ | 299 |
| | $ | 175 |
| | $ | 110 |
| | $ | 82 |
| | $ | 325 |
| | | $ | 94 |
|
Regulatory assets | 170 |
| | — |
| | 72 |
| | 20 |
| | 77 |
| | 92 |
| | 45 |
| | 99 |
| | 232 |
| 407 |
| | — |
| | 67 |
| | 26 |
| | 124 |
| | 120 |
| | 47 |
| | 83 |
| | 190 |
| | | 58 |
|
Amortization of intangible assets, net | 54 |
| | 47 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 52 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of energy contract assets and liabilities(a) | 22 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 35 |
| | 35 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Nuclear fuel(b) | 1,116 |
| | 1,116 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 1,159 |
| | 1,159 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
ARO accretion(c) | 398 |
| | 397 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 446 |
| | 446 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Total depreciation, amortization and accretion | $ | 3,987 |
| | $ | 2,589 |
|
| $ | 707 |
|
| $ | 260 |
|
| $ | 366 |
|
| $ | 256 |
|
| $ | 148 |
|
| $ | 175 |
| | $ | 624 |
| $ | 5,576 |
| | $ | 3,519 |
|
| $ | 775 |
|
| $ | 270 |
|
| $ | 423 |
|
| $ | 295 |
|
| $ | 157 |
|
| $ | 165 |
| | $ | 515 |
| | | $ | 152 |
|
__________
| |
(a) | Included in Operating revenues or Purchased power and fuel onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(b) | Included in Purchased power and fuel expense onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
| |
(c) | Included in Operating and maintenance expense onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 2,430 |
| | $ | 391 |
| | $ | 307 |
| | $ | 103 |
| | $ | 96 |
| | $ | 236 |
| | $ | 114 |
| | $ | 49 |
| | $ | 59 |
|
Income taxes (net of refunds) | 540 |
| | 337 |
| | 83 |
| | 47 |
| | (2 | ) | | (144 | ) | | (104 | ) | | (49 | ) | | (2 | ) |
Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 643 |
| | $ | 227 |
| | $ | 176 |
| | $ | 29 |
| | $ | 62 |
| | $ | 94 |
| | $ | 25 |
| | $ | 13 |
| | $ | 13 |
|
Loss (Gain) from equity method investments | 32 |
| | 33 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
Provision for uncollectible accounts | 125 |
| | 38 |
| | 34 |
| | 26 |
| | 8 |
| | 19 |
| | 8 |
| | 3 |
| | 8 |
|
Provision for excess and obsolete inventory | 56 |
| | 51 |
| | 3 |
| | — |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | — |
|
Stock-based compensation costs | 88 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (313 | ) | | (313 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 4 |
| | 2 |
| | 1 |
| | 1 |
|
Amortization of rate stabilization deferral | (10 | ) | | — |
| | — |
| | — |
| | 7 |
| | (17 | ) | | (17 | ) | | — |
| | — |
|
Amortization of debt fair value adjustment | (18 | ) | | (12 | ) | | — |
| | — |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
|
Merger-related commitments (c) | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (6 | ) | | (2 | ) | | — |
|
Severance costs | 35 |
| | 31 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Amortization of debt costs | 64 |
| | 37 |
| | 5 |
| | 2 |
| | 2 |
| | 4 |
| | 2 |
| | — |
| | 1 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Discrete impacts from EIMA and FEJA(d) | (52 | ) | | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Vacation accrual adjustment(e) | (68 | ) | | (35 | ) | | (12 | ) | | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
|
Long-term incentive plan | 109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Change in environmental liabilities | 44 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | (30 | ) | | 4 |
| | 6 |
| | (4 | ) | | (14 | ) | | (27 | ) | | (12 | ) | | (7 | ) | | (6 | ) |
Total other non-cash operating activities | $ | 721 |
|
| $ | 112 |
|
| $ | 164 |
|
| $ | 54 |
|
| $ | 65 |
|
| $ | 59 |
| | $ | (5 | ) | | $ | 9 |
| | $ | 17 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
Increase (decrease) in capital expenditures not paid | $ | 42 |
| | $ | 73 |
| | $ | (61 | ) | | $ | 22 |
| | $ | 23 |
| | $ | (12 | ) | | $ | 5 |
| | $ | 4 |
| | $ | (13 | ) |
Change in PPE related to ARO update | 29 |
| | 29 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-cash financing of capital projects | 16 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| — |
|
Indemnification of like-kind exchange position (f) | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dividends on stock compensation | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dissolution of financing trust due to long-term debt retirement | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
|
Fair value adjustment of long-term debt due to retirement | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fair value of pension and OPEB obligation transferred in connection with FitzPatrick | — |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2018 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 1,421 |
| | $ | 369 |
| | $ | 332 |
| | $ | 125 |
| | $ | 94 |
| | $ | 250 |
| | $ | 123 |
| | $ | 56 |
| | $ | 61 |
|
Income taxes (net of refunds) | 95 |
| | 746 |
| | (153 | ) | | (2 | ) | | 14 |
| | (32 | ) | | 41 |
| | (6 | ) | | (12 | ) |
Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 583 |
| | $ | 204 |
| | $ | 177 |
| | $ | 18 |
| | $ | 59 |
| | $ | 67 |
| | $ | 15 |
| | $ | 6 |
| | $ | 12 |
|
Loss (gain) from equity method investments | 28 |
| | 30 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
Provision for uncollectible accounts | 159 |
| | 48 |
| | 40 |
| | 33 |
| | 10 |
| | 28 |
| | 11 |
| | 6 |
| | 11 |
|
Provision for excess and obsolete inventory | 24 |
| | 20 |
| | 3 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Stock-based compensation costs | 75 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (2 | ) | | (2 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 10 |
| | 10 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of regulatory asset related to debt costs | 8 |
| | — |
| | 3 |
| | 1 |
| | — |
| | 4 |
| | 2 |
| | 1 |
| | 1 |
|
Amortization of rate stabilization deferral | 14 |
| | — |
| | — |
| | — |
| | — |
| | 14 |
| | 14 |
| | — |
| | — |
|
Amortization of debt fair value adjustment | (15 | ) | | (12 | ) | | — |
| | — |
| | — |
| | (3 | ) | | — |
| | — |
| | — |
|
Merger-related commitments(c) | — |
| | — |
| | — |
| | — |
| | — |
| | 5 |
| | — |
| | 5 |
| | — |
|
Severance costs | 35 |
| | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Asset retirement costs | 20 |
| | — |
| | — |
| | — |
| | — |
| | 20 |
| | 22 |
| | (1 | ) | | (1 | ) |
Amortization of debt costs | 36 |
| | 14 |
| | 5 |
| | 2 |
| | 1 |
| | 3 |
| | 2 |
| | — |
| | 1 |
|
Discrete impacts from EIMA and FEJA(d) | 28 |
| | — |
| | 28 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Long-term incentive plan | 140 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | (19 | ) | | (23 | ) | | (14 | ) | | (3 | ) | | (12 | ) | | 6 |
| | (6 | ) | | 7 |
| | — |
|
Total other non-cash operating activities | $ | 1,124 |
|
| $ | 298 |
|
| $ | 242 |
|
| $ | 51 |
|
| $ | 58 |
|
| $ | 143 |
| | $ | 60 |
| | $ | 24 |
| | $ | 24 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
Change in capital expenditures not paid | $ | (69 | ) | | $ | (199 | ) | | $ | 11 |
| | $ | (12 | ) | | $ | 50 |
| | $ | 93 |
| | $ | 20 |
| | $ | 22 |
| | $ | 46 |
|
Change in PPE related to ARO update | (107 | ) | | (130 | ) | | 7 |
| | — |
| | 1 |
| | 15 |
| | 12 |
| | 2 |
| | 1 |
|
Dividends on stock compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Acquisition of land | 3 |
| | — |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | 3 |
|
__________
| |
(a) | Includes the elimination of NDT fund activitydecommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 45 - Mergers, Acquisitions and Dispositions for moreadditional information. |
| |
(d) | Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2017 |
| | | | | | | | | | | Successor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 2,430 |
| | $ | 391 |
| | $ | 307 |
| | $ | 103 |
| | $ | 96 |
| | $ | 236 |
| | $ | 114 |
| | $ | 49 |
| | $ | 59 |
|
Income taxes (net of refunds) | 540 |
| | 337 |
| | 83 |
| | 47 |
| | (2 | ) | | (144 | ) | | (104 | ) | | (49 | ) | | (2 | ) |
Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 643 |
| | $ | 227 |
| | $ | 176 |
| | $ | 29 |
| | $ | 62 |
| | $ | 94 |
| | $ | 25 |
| | $ | 13 |
| | $ | 13 |
|
Loss (gain) from equity method investments | 32 |
| | 33 |
| | — |
| | — |
| | — |
| | (1 | ) | | — |
| | — |
| | — |
|
Provision for uncollectible accounts | 125 |
| | 38 |
| | 34 |
| | 26 |
| | 8 |
| | 19 |
| | 8 |
| | 3 |
| | 8 |
|
Provision for excess and obsolete inventory | 56 |
| | 51 |
| | 3 |
| | — |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | — |
|
Stock-based compensation costs | 88 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (313 | ) | | (313 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 7 |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 4 |
| | 2 |
| | 1 |
| | 1 |
|
Amortization of rate stabilization deferral | (10 | ) | | — |
| | — |
| | — |
| | 7 |
| | (17 | ) | | (17 | ) | | — |
| | — |
|
Amortization of debt fair value adjustment | (18 | ) | | (12 | ) | | — |
| | — |
| | — |
| | (6 | ) | | — |
| | — |
| | — |
|
Merger-related commitments(c) | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | (6 | ) | | (2 | ) | | — |
|
Severance costs | 35 |
| | 31 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | — |
|
Amortization of debt costs | 64 |
| | 37 |
| | 5 |
| | 2 |
| | 2 |
| | 4 |
| | 2 |
| | — |
| | 1 |
|
Discrete impacts from EIMA and FEJA(d) | (52 | ) | | — |
| | (52 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Vacation accrual adjustment(e) | (68 | ) | | (35 | ) | | (12 | ) | | — |
| | — |
| | (8 | ) | | (8 | ) | | — |
| | — |
|
Long-term incentive plan | 109 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Change in environmental liabilities | 44 |
| | 44 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | (30 | ) | | 4 |
| | 6 |
| | (4 | ) | | (14 | ) | | (28 | ) | | (13 | ) | | (7 | ) | | (6 | ) |
Total other non-cash operating activities | $ | 721 |
|
| $ | 112 |
|
| $ | 164 |
|
| $ | 54 |
|
| $ | 65 |
| | $ | 58 |
|
| $ | (6 | ) |
| $ | 9 |
|
| $ | 17 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
Change in capital expenditures not paid | $ | 42 |
| | $ | 73 |
| | $ | (61 | ) | | $ | 22 |
| | $ | 23 |
| | $ | (12 | ) | | $ | 5 |
| | $ | 4 |
| | $ | (13 | ) |
Change in PPE related to ARO update | 29 |
| | 29 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-cash financing of capital projects | 16 |
| | 16 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Indemnification of like-kind exchange position(f) | — |
| | — |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dividends on stock compensation | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dissolution of financing trust due to long-term debt retirement | 8 |
| | — |
| | — |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Fair value adjustment of long-term debt due to retirement | (5 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Fair value of pension and OPEB obligation transferred in connection with FitzPatrick | — |
| | 33 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
__________
| |
(a) | Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 5 - Mergers, Acquisitions and Dispositions for additional information. |
| |
(d) | Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 34 — Regulatory Matters for moreadditional information. |
| |
(e) | On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that will now be accrued ratably over the year in 2018. |
| |
(f) | See Note 14 — Income Taxes for discussion ofadditional information on the like-kind exchange tax position. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 1,340 |
| | $ | 339 |
| | $ | 298 |
| | $ | 104 |
| | $ | 92 |
| | $ | 118 |
| | $ | 47 |
| | $ | 62 |
| | $ | 209 |
| | | $ | 43 |
|
Income taxes (net of refunds) | (441 | ) | | 435 |
| | (444 | ) | | 64 |
| | 31 |
| | 216 |
| | 115 |
| | 200 |
| | 258 |
| | | 11 |
|
Other non-cash operating activities: | | | | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 619 |
| | $ | 218 |
| | $ | 166 |
| | $ | 33 |
| | $ | 67 |
| | $ | 31 |
| | $ | 18 |
| | $ | 15 |
| | $ | 86 |
| | | $ | 23 |
|
Loss from equity method investments | 24 |
| | 25 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Provision for uncollectible accounts | 155 |
| | 19 |
| | 41 |
| | 30 |
| | 1 |
| | 29 |
| | 23 |
| | 32 |
| | 65 |
| | | 16 |
|
Stock-based compensation costs | 111 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 3 |
|
Other decommissioning-related activity(a) | (384 | ) | | (384 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Energy-related options(b) | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | 3 |
| | | 1 |
|
Amortization of rate stabilization deferral | 76 |
| | — |
| | — |
| | — |
| | 81 |
| | (12 | ) | | 2 |
| | — |
| | (5 | ) | | | 5 |
|
Amortization of debt fair value adjustment | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Merger-related commitments(c)(d) | 558 |
| | 53 |
| | — |
| | — |
| | — |
| | 125 |
| | 82 |
| | 110 |
| | 317 |
| | | — |
|
Severance costs | 99 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
| | | — |
|
Discrete impacts from EIMA(e) | 8 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of debt costs | 35 |
| | 17 |
| | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| For the year ended December 31, 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 1,340 |
| | $ | 339 |
| | $ | 298 |
| | $ | 104 |
| | $ | 92 |
| | $ | 118 |
| | $ | 47 |
| | $ | 62 |
| | $ | 209 |
| | | $ | 43 |
|
Income taxes (net of refunds) | (441 | ) | | 435 |
| | (444 | ) | | 64 |
| | 31 |
| | 216 |
| | 115 |
| | 200 |
| | 258 |
| | | 11 |
|
Other non-cash operating activities: | | | | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 619 |
| | $ | 218 |
| | $ | 166 |
| | $ | 33 |
| | $ | 67 |
| | $ | 31 |
| | $ | 18 |
| | $ | 15 |
| | $ | 86 |
| | | $ | 23 |
|
Loss from equity method investments | 24 |
| | 25 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Provision for uncollectible accounts | 155 |
| | 19 |
| | 41 |
| | 30 |
| | 1 |
| | 29 |
| | 23 |
| | 32 |
| | 65 |
| | | 16 |
|
Stock-based compensation costs | 111 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | 3 |
|
Other decommissioning-related activity(a) | (384 | ) | | (384 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Energy-related options(b) | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of regulatory asset related to debt costs | 9 |
| | — |
| | 4 |
| | 1 |
| | — |
| | 2 |
| | 1 |
| | 1 |
| | 3 |
| | | 1 |
|
Amortization of rate stabilization deferral | 76 |
| | — |
| | — |
| | — |
| | 81 |
| | (12 | ) | | 2 |
| | — |
| | (5 | ) | | | 5 |
|
Amortization of debt fair value adjustment | (11 | ) | | (11 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Merger-related commitments (c)(d) | 558 |
| | 53 |
| | — |
| | — |
| | — |
| | 125 |
| | 82 |
| | 110 |
| | 317 |
| | | — |
|
Severance costs | 99 |
| | 22 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 56 |
| | | — |
|
Discrete impacts from EIMA(e) | 8 |
| | — |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Amortization of debt costs | 35 |
| | 17 |
| | 4 |
| | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | | — |
|
Provision for excess and obsolete inventory | 12 |
| | 6 |
| | 4 |
| | — |
| | — |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | | 1 |
|
Lower of cost or market inventory adjustment | 37 |
| | 36 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Baltimore City Conduit Lease Settlement | (28 | ) | | — |
| | — |
| | — |
| | (28 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
Cash Working Capital Order | (13 | ) | | — |
| | — |
| | — |
| | (13 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
Asset Retirement Costs | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 2 |
| | 2 |
| | | — |
|
Long-term incentive plan | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other | (35 | ) | | 25 |
| | (12 | ) | | (3 | ) | | (21 | ) | | 5 |
| | (14 | ) | | (6 | ) | | (12 | ) | | | (3 | ) |
Total other non-cash operating activities | $ | 1,333 |
|
| $ | 15 |
|
| $ | 215 |
|
| $ | 65 |
|
| $ | 88 |
|
| $ | 183 |
|
| $ | 114 |
|
| $ | 155 |
|
| $ | 514 |
| | | $ | 46 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | | | | |
Increase (decrease) in capital expenditures not paid
| $ | (128 | ) | | $ | 50 |
| | $ | (91 | ) | | $ | (11 | ) | | $ | (86 | ) | | $ | 27 |
| | $ | (12 | ) | | $ | 11 |
| | $ | 21 |
| | | $ | 11 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | Provision for excess and obsolete inventory | | 12 |
| | 6 |
| | 4 |
| | — |
| | — |
| | 3 |
| | 1 |
| | 1 |
| | 1 |
| | | 1 |
|
Lower of cost or market inventory adjustment | | 37 |
| | 36 |
| | — |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Baltimore City Conduit Lease Settlement | | (28 | ) | | — |
| | — |
| | — |
| | (28 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
Cash Working Capital Order | | (13 | ) | | — |
| | — |
| | — |
| | (13 | ) | | — |
| | — |
| | — |
| | — |
| | | — |
|
Asset retirement costs | | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 1 |
| | 2 |
| | 2 |
| | | — |
|
Long-term incentive plan | | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other | | (35 | ) | | 25 |
| | (12 | ) | | (3 | ) | | (21 | ) | | (3 | ) | | (14 | ) | | (6 | ) | | (11 | ) | | | (3 | ) |
Total other non-cash operating activities | | $ | 1,333 |
|
| $ | 15 |
|
| $ | 215 |
|
| $ | 65 |
|
| $ | 88 |
|
| $ | 175 |
| | $ | 114 |
| | $ | 155 |
| | $ | 515 |
| | | $ | 46 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | | | | | |
Change in capital expenditures not paid | | $ | (128 | ) | | $ | 50 |
| | $ | (91 | ) | | $ | (11 | ) | | $ | (86 | ) | | $ | 27 |
| | $ | (12 | ) | | $ | 11 |
| | $ | 21 |
| | | $ | 11 |
|
Change in PPE related to ARO update | 191 |
| | 191 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 191 |
| | 191 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Indemnification of like-kind exchange position(g)
| — |
| | — |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| — |
| | — |
| | 158 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Dividends on stock compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Non-cash financing of capital projects | 95 |
| | 95 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 95 |
| | 95 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Sale of Upstream assets(c) | 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Pending FitzPatrick Acquisition(h) | (54 | ) | | (54 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| (54 | ) | | (54 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash | — |
| | 119 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
| — |
| | 119 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash (c)(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 127 |
| | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 127 |
| | | — |
|
Fair value of pension obligation transferred in connection with the PHI Merger (c)(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 53 |
| | | — |
| |
Fair value of pension obligation transferred in connection with the PHI Merger, net of cash(c)(f) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 53 |
| | | — |
|
Assumption of member purchase liability | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 29 |
| | | — |
|
Assumption of merger commitment liability | — |
| | — |
| | — |
| | — |
| | — |
| | 33 |
| | — |
| | — |
| | 33 |
| | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 33 |
| | — |
| | — |
| | 33 |
| | | — |
|
__________
| |
(a) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | See Note 45 - Mergers, Acquisitions and Dispositions for moreadditional information. |
| |
(d) | Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts. |
| |
(e) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 34 — Regulatory Matters for moreadditional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(f) | Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation. |
| |
(g) | See Note 14 — Income Taxes for discussion ofadditional information on the like-kind exchange tax position. |
| |
(h) | Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 45 - Mergers, Acquisitions and Dispositions for moreadditional information. |
The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash and cash equivalents | $ | 1,349 |
| | $ | 750 |
| | $ | 135 |
| | $ | 130 |
| | $ | 7 |
| | $ | 124 |
| | $ | 16 |
| | $ | 23 |
| | $ | 7 |
|
Restricted cash | 247 |
| | 153 |
| | 29 |
| | 5 |
| | 6 |
| | 43 |
| | 37 |
| | 1 |
| | 4 |
|
Restricted cash included in other long-term assets | 185 |
| | — |
| | 166 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | 19 |
|
Total cash, cash equivalents and restricted cash | $ | 1,781 |
| | $ | 903 |
| | $ | 330 |
| | $ | 135 |
| | $ | 13 |
| | $ | 186 |
| | $ | 53 |
| | $ | 24 |
| | $ | 30 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash and cash equivalents | $ | 898 |
| | $ | 416 |
| | $ | 76 |
| | $ | 271 |
| | $ | 17 |
| | $ | 30 |
| | $ | 5 |
| | $ | 2 |
| | $ | 2 |
|
Restricted cash | 207 |
| | 138 |
| | 5 |
| | 4 |
| | 1 |
| | 42 |
| | 35 |
| | — |
| | 6 |
|
Restricted cash included in other long-term assets | 85 |
| | — |
| | 63 |
| | — |
| | — |
| | 23 |
| | — |
| | — |
| | 23 |
|
Total cash, cash equivalents and restricted cash | $ | 1,190 |
| | $ | 554 |
| | $ | 144 |
| | $ | 275 |
| | $ | 18 |
| | $ | 95 |
| | $ | 40 |
| | $ | 2 |
| | $ | 31 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | Successor | | | Predecessor |
| December 31, 2016 | | December 31, 2016 | | | March 23, 2016 |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Cash and cash equivalents | $ | 635 |
| | $ | 290 |
| | $ | 56 |
| | $ | 63 |
| | $ | 23 |
| | $ | 9 |
| | $ | 46 |
| | $ | 101 |
| | $ | 170 |
| | | $ | 319 |
|
Restricted cash | 253 |
| | 158 |
| | 2 |
| | 4 |
| | 24 |
| | 33 |
| | — |
| | 9 |
| | 43 |
| | | 11 |
|
Restricted cash included in other long-term assets | 26 |
| | — |
| | — |
| | — |
| | 3 |
| | — |
| | — |
| | 23 |
| | 23 |
| | | 18 |
|
Total cash, cash equivalents and restricted cash | $ | 914 |
| | $ | 448 |
| | $ | 58 |
| | $ | 67 |
| | $ | 50 |
| | $ | 42 |
| | $ | 46 |
| | $ | 133 |
| | $ | 236 |
| | | $ | 348 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Predecessor | | | | | | |
December 31, 2015 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash and cash equivalents | $ | 6,502 |
| | $ | 431 |
| | $ | 67 |
| | $ | 295 |
| | $ | 9 |
| | $ | 26 |
| | $ | 5 |
| | $ | 5 |
| | $ | 3 |
|
Restricted cash | 205 |
| | 123 |
| | 2 |
| | 3 |
| | 24 |
| | 14 |
| | 2 |
| | — |
| | 12 |
|
Restricted cash included in other long-term assets | 5 |
| | 2 |
| | — |
| | — |
| | 3 |
| | 18 |
| | — |
| | — |
| | 18 |
|
Total cash, cash equivalents and restricted cash | $ | 6,712 |
| | $ | 556 |
| | $ | 69 |
| | $ | 298 |
| | $ | 36 |
| | $ | 58 |
| | $ | 7 |
| | $ | 5 |
| | $ | 33 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2018 and 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unbilled customer revenues(a) | $ | 1,656 |
| | $ | 965 |
| | $ | 223 |
| | $ | 114 |
| | $ | 168 |
| | $ | 186 |
| | $ | 97 |
| | $ | 59 |
| | $ | 30 |
|
Allowance for uncollectible accounts (b) | (319 | ) | | (104 | ) | | (81 | ) | | (61 | ) | | (20 | ) | | (53 | ) | | (21 | ) | | (13 | ) | | (19 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Unbilled customer revenues(a) | $ | 1,858 |
| | $ | 1,017 |
| | $ | 242 |
| | $ | 162 |
| | $ | 205 |
| | $ | 232 |
| | $ | 133 |
| | $ | 68 |
| | $ | 31 |
|
Allowance for uncollectible accounts(b) | (322 | ) | | (114 | ) | | (73 | ) | | (56 | ) | | (24 | ) | | (55 | ) | | (21 | ) | | (16 | ) | | (18 | ) |
__________
| |
(a) | Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy. |
| |
(b) | Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable. |
The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that 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 and ACE purchase receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive Income and are classified in Other accounts receivable, net in their Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of December 31, 2018 and 2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Purchased receivables | $ | 313 |
| | $ | 94 |
| | $ | 74 |
| | $ | 61 |
| | $ | 84 |
| | $ | 57 |
| | $ | 8 |
| | $ | 19 |
|
Allowance for uncollectible accounts(a) | (34 | ) | | (17 | ) | | (5 | ) | | (3 | ) | | (9 | ) | | (5 | ) | | (1 | ) | | (3 | ) |
Purchased receivables, net | $ | 279 |
| | $ | 77 |
| | $ | 69 |
| | $ | 58 |
| | $ | 75 |
| | $ | 52 |
| | $ | 7 |
| | $ | 16 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | Exelon | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Purchased receivables | $ | 298 |
| | $ | 87 |
| | $ | 70 |
| | $ | 58 |
| | $ | 83 |
| | $ | 56 |
| | $ | 9 |
| | $ | 18 |
|
Allowance for uncollectible accounts(a) | (31 | ) | | (14 | ) | | (5 | ) | | (3 | ) | | (9 | ) | | (5 | ) | | (1 | ) | | (3 | ) |
Purchased receivables, net | $ | 267 |
| | $ | 73 |
| | $ | 65 |
| | $ | 55 |
| | $ | 74 |
| | $ | 51 |
| | $ | 8 |
| | $ | 15 |
|
__________
| |
(a) | For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| For the year ended December 31, 2015 |
| | | | | | | | | | | Predecessor | | | | | | |
| Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Cash paid (refunded) during the year: | | | | | | | | | | | | | | | | | |
Interest (net of amount capitalized) | $ | 930 |
| | $ | 348 |
| | $ | 308 |
| | $ | 94 |
| | $ | 120 |
| | $ | 268 |
| | $ | 116 |
| | $ | 47 |
| | $ | 63 |
|
Income taxes (net of refunds) | 342 |
| | 476 |
| | (265 | ) | | 64 |
| | 73 |
| | (13 | ) | | (6 | ) | | (5 | ) | | — |
|
Other non-cash operating activities: | | | | | | | | | | | | | | | | | |
Pension and non-pension postretirement benefit costs | $ | 637 |
| | $ | 269 |
| | $ | 206 |
| | $ | 39 |
| | $ | 65 |
| | $ | 97 |
| | $ | 30 |
| | $ | 15 |
| | $ | 15 |
|
Loss from equity method investments | 7 |
| | 8 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Provision for uncollectible accounts | 120 |
| | 22 |
| | 53 |
| | 30 |
| | 15 |
| | 61 |
| | 21 |
| | 20 |
| | 20 |
|
Provision for excess and obsolete inventory | 10 |
| | 9 |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | — |
| | — |
|
Stock-based compensation costs | 97 |
| | — |
| | — |
| | — |
| | — |
| | 13 |
| | — |
| | — |
| | — |
|
Other decommissioning-related activity(a) | (82 | ) | | (82 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Energy-related options(b) | 21 |
| | 21 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of regulatory asset related to debt costs | 7 |
| | — |
| | 5 |
| | 2 |
| | — |
| | 5 |
| | 2 |
| | 1 |
| | 1 |
|
Amortization of rate stabilization deferral | 73 |
| | — |
| | — |
| | — |
| | 73 |
| | (2 | ) | | 1 |
| | (3 | ) | | — |
|
Amortization of debt fair value adjustment | (17 | ) | | (17 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Discrete impacts from EIMA(c) | 144 |
| | — |
| | 144 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of debt costs | 58 |
| | 15 |
| | 4 |
| | 2 |
| | 2 |
| | 2 |
| | — |
| | — |
| | — |
|
Lower of cost or market inventory adjustment | 23 |
| | 23 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Long-term incentive plan | 24 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | (13 | ) | | — |
| | 3 |
| | (3 | ) | | (18 | ) | | (10 | ) | | — |
| | — |
| | 1 |
|
Total other non-cash operating activities | $ | 1,109 |
|
| $ | 268 |
|
| $ | 416 |
|
| $ | 70 |
|
| $ | 137 |
|
| $ | 167 |
| | $ | 54 |
| | $ | 33 |
| | $ | 37 |
|
Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
Change in PPE related to ARO update | $ | 885 |
| | $ | 885 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Increase (decrease) in capital expenditures not paid
| 96 |
| | 82 |
| | 34 |
| | (13 | ) | | (9 | ) | | 6 |
| | (1 | ) | | 3 |
| | 3 |
|
Nuclear fuel procurement(d) | 57 |
| | 57 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Indemnification of like-kind exchange position(e) | — |
| | — |
| | 7 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Dividends on stock compensation | 6 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Non-cash financing of capital projects | 77 |
| | 77 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Long-term software licensing agreement(f) | 95 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
__________
| |
(a) | Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning. |
| |
(b) | Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations. |
| |
(c) | Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 3 — Regulatory Matters for more information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(d) | Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2015. Generation is required to make payments starting September 30, 2018, with the final payment being due no later than September 30, 2020. |
| |
(e) | See Note 14 — Income Taxes for discussion of the like-kind exchange tax position. |
| |
(f) | Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 13 - Debt and Credit Agreements. |
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the RegistrantsRegistrants' investments at December 31, 20172018 and 2016.2017.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | |
December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Investments | | | | | | | | | | | | | | | | | |
Equity method investments: | | | | | | | | | | | | | | | | | |
Financing trusts(a) | $ | 14 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Bloom | 206 |
| | 206 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net Power | 76 |
| | 76 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other equity method investments | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total equity method investments | 297 |
|
| 283 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(b) | 244 |
| | 51 |
| | — |
| | 17 |
| | 5 |
| | 132 |
| | 102 |
| | — |
| | — |
|
Other cost method investments | 62 |
| | 62 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other available for sale investments | 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total investments | $ | 640 |
|
| $ | 433 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | 132 |
|
| $ | 102 |
|
| $ | — |
|
| $ | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Investments | | | | | | | | | | | | | | | | | |
Equity method investments: | | | | | | | | | | | | | | | | | |
Financing trusts(a) | $ | 14 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Bloom | 180 |
| | 180 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
NET Power | 70 |
| | 70 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other equity method investments | 3 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total equity method investments | 267 |
|
| 251 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Other investments: | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(b) | 244 |
| | 49 |
| | — |
| | 17 |
| | 5 |
| | 130 |
| | 105 |
| | — |
| | — |
|
Equity investments without readily determinable fair values | 72 |
| | 72 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other available for sale debt security investments | 40 |
| | 40 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other | 2 |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total investments | $ | 625 |
|
| $ | 414 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | 130 |
|
| $ | 105 |
|
| $ | — |
|
| $ | — |
|
| | | | | | | | | | | | | Successor | | | | | | | |
December 31, 2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
December 31, 2017 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Investments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity method investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Financing trusts(a) | $ | 22 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | 14 |
| | $ | — |
| | $ | 6 |
| | $ | 8 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
Bloom | 216 |
| | 216 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 206 |
| | 206 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Net Power | 57 |
| | 57 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
NET Power | | 76 |
| | 76 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other equity method investments | 16 |
| | 15 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| 1 |
| | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total equity method investments | 311 |
|
| 288 |
|
| 6 |
|
| 8 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
| 297 |
|
| 283 |
|
| 6 |
|
| 8 |
|
| — |
|
| — |
|
| — |
|
| — |
|
| — |
|
Other investments: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Employee benefit trusts and investments(b) | 232 |
| | 44 |
| | — |
| | 17 |
| | 4 |
| | 133 |
| | 102 |
| | — |
| | — |
| 244 |
| | 51 |
| | — |
| | 17 |
| | 5 |
| | 132 |
| | 102 |
| | — |
| | — |
|
Other cost method investments | 52 |
| | 52 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Other available for sale investments | 34 |
| | 34 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Equity investments without readily determinable fair values | | 62 |
| | 62 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Other available for sale debt security investments | | 37 |
| | 37 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Total investments | $ | 629 |
|
| $ | 418 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 12 |
|
| $ | 133 |
|
| $ | 102 |
|
| $ | — |
|
| $ | — |
| $ | 640 |
|
| $ | 433 |
|
| $ | 6 |
|
| $ | 25 |
|
| $ | 5 |
|
| $ | 132 |
|
| $ | 102 |
|
| $ | — |
|
| $ | — |
|
__________
| |
(a) | Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments onin the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information. |
| |
(b) | The Registrants’ debt and equity security investments in these marketable securities are recorded at fair market value. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide additional information about liabilities of the Registrants at December 31, 20172018 and 2016.2017.
| | December 31, 2018 | | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Accrued expenses | | Accrued expenses | | | | | | | | | | | | | | |
Compensation-related accruals(a) | | $ | 1,191 |
| | $ | 479 |
| | $ | 187 |
| | $ | 49 |
| | $ | 68 |
| | $ | 99 |
| | $ | 29 |
| | $ | 19 |
| | $ | 12 |
|
Taxes accrued | | 412 |
| | 226 |
| | 71 |
| | 28 |
| | 46 |
| | 74 |
| | 58 |
| | 4 |
| | 5 |
|
Interest accrued | | 334 |
| | 77 |
| | 105 |
| | 33 |
| | 39 |
| | 50 |
| | 25 |
| | 8 |
| | 12 |
|
Severance accrued | | 44 |
| | 26 |
| | 2 |
| | — |
| | — |
| | 5 |
| | — |
| | — |
| | — |
|
Other accrued expenses | | 131 |
| | 90 |
|
| 8 |
| | 3 |
| | 2 |
| | 28 |
| | 14 |
| | 8 |
| | 6 |
|
Total accrued expenses | | $ | 2,112 |
| | $ | 898 |
| | $ | 373 |
| | $ | 113 |
| | $ | 155 |
|
| $ | 256 |
|
| $ | 126 |
|
| $ | 39 |
|
| $ | 35 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2017 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Accrued expenses | Accrued expenses | | | | | | | | | | | | | | | Accrued expenses | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 978 |
| | $ | 407 |
| | $ | 158 |
| | $ | 64 |
| | $ | 58 |
| | $ | 106 |
| | $ | 29 |
| | $ | 17 |
| | $ | 11 |
| $ | 978 |
| | $ | 407 |
| | $ | 158 |
| | $ | 64 |
| | $ | 58 |
| | $ | 106 |
| | $ | 29 |
| | $ | 17 |
| | $ | 11 |
|
Taxes accrued | 373 |
| | 444 |
| | 60 |
| | 15 |
| | 71 |
| | 61 |
| | 68 |
| | 4 |
| | 5 |
| 373 |
| | 444 |
| | 60 |
| | 15 |
| | 71 |
| | 61 |
| | 68 |
| | 4 |
| | 5 |
|
Interest accrued | 328 |
| | 78 |
| | 102 |
| | 33 |
| | 34 |
| | 48 |
| | 23 |
| | 8 |
| | 12 |
| 328 |
| | 78 |
| | 102 |
| | 33 |
| | 34 |
| | 48 |
| | 23 |
| | 8 |
| | 12 |
|
Severance accrued | 58 |
| | 30 |
| | 2 |
| | — |
| | — |
| | 17 |
| | — |
| | — |
| | — |
| 58 |
| | 30 |
| | 2 |
| | — |
| | — |
| | 17 |
| | — |
| | — |
| | — |
|
Other accrued expenses | 98 |
| | 61 |
|
| 5 |
| | 2 |
| | 1 |
| | 29 |
| | 17 |
| | 6 |
| | 5 |
| 100 |
| | 63 |
|
| 5 |
| | 2 |
| | 1 |
| | 29 |
| | 17 |
| | 6 |
| | 5 |
|
Total accrued expenses | $ | 1,835 |
| | $ | 1,020 |
| | $ | 327 |
| | $ | 114 |
| | $ | 164 |
|
| $ | 261 |
|
| $ | 137 |
|
| $ | 35 |
|
| $ | 33 |
| $ | 1,837 |
| | $ | 1,022 |
| | $ | 327 |
| | $ | 114 |
| | $ | 164 |
|
| $ | 261 |
|
| $ | 137 |
|
| $ | 35 |
|
| $ | 33 |
|
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Successor | | | | | | | |
December 31, 2016 | Exelon | | Generation | | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE | |
Accrued expenses | | | | | | | | | | | | | | | |
Compensation-related accruals(a) | $ | 1,199 |
| | $ | 557 |
| | $ | 199 |
| | $ | 67 |
| | $ | 64 |
| | $ | 112 |
| | $ | 30 |
| | $ | 17 |
| | $ | 11 |
| |
Taxes accrued | 723 |
| | 239 |
| | 330 |
| | 4 |
| | 78 |
| | 65 |
| | 48 |
| | 4 |
| | 9 |
| |
Interest accrued | 1,234 |
| | 82 |
| | 609 |
| | 30 |
| | 31 |
| | 49 |
| | 21 |
| | 8 |
| | 12 |
| |
Severance accrued | 44 |
| | 15 |
| | 2 |
| | — |
| | — |
| | 19 |
| | — |
| | — |
| | — |
| |
Other accrued expenses | 260 |
| | 96 |
|
| 110 |
| | 3 |
| | 2 |
| | 27 |
| | 14 |
| | 7 |
| | 6 |
| |
Total accrued expenses | $ | 3,460 |
| | $ | 989 |
| | $ | 1,250 |
| | $ | 104 |
| | $ | 175 |
|
| $ | 272 |
|
| $ | 113 |
|
| $ | 36 |
|
| $ | 38 |
| |
__________
| |
(a) | Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits. |
25.24. 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’sGeneration's six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada.ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income 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 was recast in 2016 to conform to the current Exelon presentation. The reclassification of the segment information did not impact PHI's reported consolidated revenues or net income. PHI's CODM evaluates the
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.Region.
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.ISO-NE.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.ISO-NY.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
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.PJM.
West represents operations in the WECC, which includesincluding California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.ISO.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on revenues net of purchased power and fuel expense (RNF).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
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further, Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Beginning in the first quarter of 2019, Other Power Regions will include:
South represents operations in the FRCC, MISO’s Southern Region, the remaining portions of the SERC not included within MISO or PJM.
West represents operations in the WECC, including California ISO.
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
New England represents operations within ISO-NE.
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 years ended December 31, 2018, 2017, 2016, and 20152016 is as follows:
| | | | | | | | | | | Successor | | | | | | | | | | | | | | | Successor | | | | | | |
| Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment Eliminations |
| Exelon | Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment Eliminations |
| Exelon |
Operating revenues(c): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2018 | | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | | $ | 17,411 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,256 | ) | | $ | 16,155 |
|
Competitive businesses natural gas revenues | | 2,718 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (8 | ) | | 2,710 |
|
Competitive businesses other revenues | | 308 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (5 | ) | | 303 |
|
Rate-regulated electric revenues | | — |
| | 5,882 |
| | 2,470 |
| | 2,428 |
| | 4,609 |
| | — |
| | (45 | ) | | 15,344 |
|
Rate-regulated natural gas revenues | | — |
| | — |
| | 568 |
| | 741 |
| | 181 |
| | — |
| | (20 | ) | | 1,470 |
|
Shared service and other revenues | | — |
| | — |
| | — |
| | — |
| | 15 |
| | 1,948 |
| | (1,960 | ) | | 3 |
|
Total operating revenues | | $ | 20,437 |
| | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,805 |
| | $ | 1,948 |
| | $ | (3,294 | ) | | $ | 35,985 |
|
2017 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 15,300 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,105 | ) | | $ | 14,195 |
| $ | 15,332 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,105 | ) | | $ | 14,227 |
|
Competitive businesses natural gas revenues | 2,575 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,575 |
| 2,575 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,575 |
|
Competitive businesses other revenues | 591 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 590 |
| 593 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 592 |
|
Rate-regulated electric revenues | — |
| | 5,536 |
| | 2,375 |
| | 2,489 |
| | 4,469 |
| | — |
| | (29 | ) | | 14,840 |
| — |
| | 5,536 |
| | 2,375 |
| | 2,489 |
| | 4,469 |
| | — |
| | (29 | ) | | 14,840 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 495 |
| | 687 |
| | 161 |
| | — |
| | (10 | ) | | 1,333 |
| — |
| | — |
| | 495 |
| | 687 |
| | 161 |
| | — |
| | (10 | ) | | 1,333 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 49 |
| | 1,831 |
| | (1,880 | ) | | — |
| — |
| | — |
| | — |
| | — |
| | 49 |
| | 1,831 |
| | (1,880 | ) | | — |
|
2016 | | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 15,390 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,430 | ) | | $ | 13,960 |
| |
Competitive businesses natural gas revenues | 2,146 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,146 |
| |
Competitive businesses other revenues | 215 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 211 |
| |
Rate-regulated electric revenues | — |
| | 5,254 |
| | 2,531 |
| | 2,609 |
| | 3,506 |
| | — |
| | (31 | ) | | 13,869 |
| |
Rate-regulated natural gas revenues | — |
| | — |
| | 463 |
| | 624 |
| | 92 |
| | — |
| | (13 | ) | | 1,166 |
| |
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | 45 |
| | 1,648 |
| | (1,686 | ) | | 7 |
| |
2015 | | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | $ | 15,944 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (744 | ) | | $ | 15,200 |
| |
Competitive businesses natural gas revenues | 2,433 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,433 |
| |
Total operating revenues | | $ | 18,500 |
| | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 1,831 |
| | $ | (3,025 | ) | | $ | 33,567 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | | | | | | | | | | Successor | | | | | | |
| | Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment Eliminations |
| Exelon |
2016 | | | | | | | | | | | | | | | | |
Competitive businesses electric revenues | | $ | 15,400 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | (1,430 | ) | | $ | 13,970 |
|
Competitive businesses natural gas revenues | | 2,146 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2,146 |
|
Competitive businesses other revenues | 758 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (1 | ) | | 757 |
| 211 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (4 | ) | | 207 |
|
Rate-regulated electric revenues | — |
| | 4,905 |
| | 2,486 |
| | 2,490 |
| | — |
| | — |
| | (5 | ) | | 9,876 |
| — |
| | 5,254 |
| | 2,531 |
| | 2,609 |
| | 3,506 |
| | — |
| | (31 | ) | | 13,869 |
|
Rate-regulated natural gas revenues | — |
| | — |
| | 546 |
| | 645 |
| | — |
| | — |
| | (15 | ) | | 1,176 |
| — |
| | — |
| | 463 |
| | 624 |
| | 92 |
| | — |
| | (13 | ) | | 1,166 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | — |
| | 1,372 |
| | (1,367 | ) | | 5 |
| — |
| | — |
| | — |
| | — |
| | 45 |
| | 1,648 |
| | (1,686 | ) | | 7 |
|
Total operating revenues | | $ | 17,757 |
| | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 3,643 |
| | $ | 1,648 |
| | $ | (3,164 | ) | | $ | 31,365 |
|
| | | | | | | | | | | | | | | | |
Intersegment revenues(d): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2018 | | $ | 1,269 |
| | $ | 27 |
| | $ | 8 |
| | $ | 29 |
| | $ | 15 |
| | $ | 1,942 |
| | $ | (3,289 | ) | | $ | 1 |
|
2017 | $ | 1,110 |
| | $ | 15 |
| | $ | 7 |
| | $ | 16 |
| | $ | 50 |
| | $ | 1,824 |
| | $ | (3,020 | ) | | $ | 2 |
| 1,110 |
| | 15 |
| | 7 |
| | 16 |
| | 50 |
| | 1,824 |
| | (3,020 | ) | | 2 |
|
2016 | 1,428 |
| | 15 |
| | 8 |
| | 21 |
| | 45 |
| | 1,647 |
| | (3,159 | ) | | 5 |
| 1,428 |
| | 15 |
| | 8 |
| | 21 |
| | 45 |
| | 1,647 |
| | (3,159 | ) | | 5 |
|
2015 | 745 |
| | 4 |
| | 2 |
| | 14 |
| | — |
| | 1,367 |
| | (2,127 | ) | | 5 |
| |
Depreciation and amortization: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2018 | | $ | 1,797 |
| | $ | 940 |
| | $ | 301 |
| | $ | 483 |
| | $ | 740 |
| | $ | 92 |
| | $ | — |
| | $ | 4,353 |
|
2017 | $ | 1,457 |
| | $ | 850 |
| | $ | 286 |
| | $ | 473 |
| | $ | 675 |
| | $ | 87 |
| | $ | — |
| | $ | 3,828 |
| 1,457 |
| | 850 |
| | 286 |
| | 473 |
| | 675 |
| | 87 |
| | — |
| | 3,828 |
|
2016 | 1,879 |
| | 775 |
| | 270 |
| | 423 |
| | 515 |
| | 74 |
| | — |
| | 3,936 |
| 1,879 |
| | 775 |
| | 270 |
| | 423 |
| | 515 |
| | 74 |
| | — |
| | 3,936 |
|
2015 | 1,054 |
| | 707 |
| | 260 |
| | 366 |
| | — |
| | 63 |
| | — |
| | 2,450 |
| |
Operating expenses (c): | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2018 | | $ | 19,510 |
| | $ | 4,741 |
| | $ | 2,452 |
| | $ | 2,696 |
| | $ | 4,156 |
| | $ | 1,929 |
| | $ | (3,341 | ) | | $ | 32,143 |
|
2017 | $ | 17,993 |
| | $ | 4,214 |
| | $ | 2,215 |
| | $ | 2,562 |
| | $ | 3,911 |
| | $ | 1,851 |
| | $ | (3,026 | ) | | $ | 29,720 |
| 18,001 |
| | 4,214 |
| | 2,215 |
| | 2,562 |
| | 3,911 |
| | 1,742 |
| | (3,026 | ) | | 29,619 |
|
2016 | 16,856 |
| | 4,056 |
| | 2,292 |
| | 2,683 |
| | 3,549 |
| | 1,928 |
| | (3,164 | ) | | 28,200 |
| 16,878 |
| | 4,056 |
| | 2,292 |
| | 2,683 |
| | 3,549 |
| | 1,812 |
| | (3,164 | ) | | 28,106 |
|
2015 | 16,872 |
| | 3,889 |
| | 2,404 |
| | 2,578 |
| | — |
| | 1,444 |
| | (2,131 | ) | | 25,056 |
| |
Equity in earnings (losses) of unconsolidated affiliates: | | | | | | | | | | | | | | | | |
Interest expense, net: | | | | | | | | | | | | | | | | |
2018 | | $ | 432 |
| | $ | 347 |
| | $ | 129 |
| | $ | 106 |
| | $ | 261 |
| | $ | 279 |
| | $ | — |
| | $ | 1,554 |
|
2017 | $ | (33 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | — |
| | $ | (32 | ) | 440 |
| | 361 |
| | 126 |
| | 105 |
| | 245 |
| | 283 |
| | — |
| | 1,560 |
|
2016 | (25 | ) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | (24 | ) | 364 |
| | 461 |
| | 123 |
| | 103 |
| | 195 |
| | 290 |
| | — |
| | 1,536 |
|
2015 | (8 | ) | | — |
| | — |
| | — |
| | — |
| | 1 |
| | — |
| | (7 | ) | |
Interest expense, net: | | | | | | | | | | | | | | | | |
Income (loss) before income taxes: | | | | | | | | | | | | | | | | |
2018 | | $ | 365 |
| | $ | 832 |
| | $ | 466 |
| | $ | 387 |
| | $ | 432 |
| | $ | (249 | ) | | $ | (1 | ) | | $ | 2,232 |
|
2017 | $ | 440 |
| | $ | 361 |
| | $ | 126 |
| | $ | 105 |
| | $ | 245 |
| | $ | 283 |
| | $ | — |
| | $ | 1,560 |
| 1,455 |
| | 984 |
| | 538 |
| | 525 |
| | 578 |
| | (296 | ) | | (2 | ) | | 3,782 |
|
2016 | 364 |
| | 461 |
| | 123 |
| | 103 |
| | 195 |
| | 290 |
| | — |
| | 1,536 |
| 857 |
| | 679 |
| | 587 |
| | 468 |
| | (58 | ) | | (555 | ) | | (5 | ) | | 1,973 |
|
2015 | 365 |
| | 332 |
| | 114 |
| | 99 |
| | — |
| | 123 |
| | — |
| | 1,033 |
| |
Income (loss) before income taxes: | | | | | | | | | | | | | | | | |
Income taxes: | | | | | | | | | | | | | | | | |
2018 | | $ | (108 | ) | | $ | 168 |
| | $ | 6 |
| | $ | 74 |
| | $ | 35 |
| | $ | (55 | ) | | $ | — |
| | $ | 120 |
|
2017 | $ | 1,429 |
| | $ | 984 |
| | $ | 538 |
| | $ | 525 |
| | $ | 578 |
| | $ | (296 | ) | | $ | (2 | ) | | $ | 3,756 |
| (1,376 | ) | | 417 |
| | 104 |
| | 218 |
| | 217 |
| | 294 |
| | — |
| | (126 | ) |
2016 | 873 |
| | 679 |
| | 587 |
| | 468 |
| | (58 | ) | | (555 | ) | | (5 | ) | | 1,989 |
| 282 |
| | 301 |
| | 149 |
| | 174 |
| | 3 |
| | (156 | ) | | — |
| | 753 |
|
2015 | 1,850 |
| | 706 |
| | 521 |
| | 477 |
| | — |
| | (219 | ) | | (5 | ) | | 3,330 |
| |
Income taxes: | | | | | | | | | | | | | | | | |
2017 | $ | (1,375 | ) | | $ | 417 |
| | $ | 104 |
| | $ | 218 |
| | $ | 217 |
| | $ | 294 |
| | $ | — |
| | $ | (125 | ) | |
2016 | 290 |
| | 301 |
| | 149 |
| | 174 |
| | 3 |
| | (156 | ) | | — |
| | 761 |
| |
2015 | 502 |
| | 280 |
| | 143 |
| | 189 |
| | — |
| | (41 | ) | | — |
| | 1,073 |
| |
Net income (loss): | | | | | | | | | | | | | | | | |
2017 | $ | 2,771 |
| | $ | 567 |
| | $ | 434 |
| | $ | 307 |
| | $ | 362 |
| | $ | (590 | ) | | $ | (2 | ) | | $ | 3,849 |
| |
2016 | 558 |
| | 378 |
| | 438 |
| | 294 |
| | (61 | ) | | (398 | ) | | (5 | ) | | 1,204 |
| |
2015 | 1,340 |
| | 426 |
| | 378 |
| | 288 |
| | — |
| | (177 | ) | | (5 | ) | | 2,250 |
| |
Capital expenditures: | | | | | | | | | | | | | | | | |
2017 | $ | 2,259 |
| | $ | 2,250 |
| | $ | 732 |
| | $ | 882 |
| | $ | 1,396 |
| | $ | 65 |
| | $ | — |
| | $ | 7,584 |
| |
2016 | 3,078 |
| | 2,734 |
| | 686 |
| | 934 |
| | 1,008 |
| | 113 |
| | — |
| | 8,553 |
| |
2015 | 3,841 |
| | 2,398 |
| | 601 |
| | 719 |
| | — |
| | 65 |
| | — |
| | 7,624 |
| |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | Total assets: | | | | | | | | | | | | | | | | |
| | | | | | | | | | Successor | | | | | | |
| | Generation (a) |
| ComEd |
| PECO |
| BGE |
| PHI (e) | | Other (b) |
| Intersegment Eliminations |
| Exelon |
Net income (loss): | | | | | | | | | | | | | | | | |
2018 | | $ | 443 |
| | $ | 664 |
| | $ | 460 |
| | $ | 313 |
| | $ | 398 |
| | $ | (193 | ) | | $ | (1 | ) | | $ | 2,084 |
|
2017 | $ | 48,387 |
| | $ | 29,726 |
| | $ | 10,170 |
| | $ | 9,104 |
| | $ | 21,247 |
| | $ | 8,618 |
| | $ | (10,552 | ) | | $ | 116,700 |
| 2,798 |
| | 567 |
| | 434 |
| | 307 |
| | 362 |
| | (590 | ) | | (2 | ) | | 3,876 |
|
2016 | 46,974 |
| | 28,335 |
| | 10,831 |
| | 8,704 |
| | 21,025 |
| | 10,369 |
| | (11,334 | ) | | 114,904 |
| 550 |
| | 378 |
| | 438 |
| | 294 |
| | (61 | ) | | (398 | ) | | (5 | ) | | 1,196 |
|
Capital expenditures: | | | | | | | | | | | | | | | | |
2018 | | $ | 2,242 |
| | $ | 2,126 |
| | $ | 849 |
| | $ | 959 |
| | $ | 1,375 |
| | $ | 43 |
| | $ | — |
| | $ | 7,594 |
|
2017 | | $ | 2,259 |
| | $ | 2,250 |
| | $ | 732 |
| | $ | 882 |
| | $ | 1,396 |
| | $ | 65 |
| | $ | — |
| | $ | 7,584 |
|
2016 | | $ | 3,078 |
| | $ | 2,734 |
| | $ | 686 |
| | $ | 934 |
| | $ | 1,008 |
| | $ | 113 |
| | $ | — |
| | $ | 8,553 |
|
Total assets: | | | | | | | | | | | | | | | | |
2018 | | $ | 47,556 |
| | $ | 31,213 |
| | $ | 10,642 |
| | $ | 9,716 |
| | $ | 21,984 |
| | $ | 8,355 |
| | $ | (9,800 | ) | | $ | 119,666 |
|
2017 | | 48,457 |
| | 29,726 |
| | 10,170 |
| | 9,104 |
| | 21,247 |
| | 8,618 |
| | (10,552 | ) | | 116,770 |
|
__________
| |
(a) | Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2017,See Note 25 — Related Party Transactions for additional information on intersegment revenues for Generation include revenue from sales to PECO of $138 million, sales to BGE of $388 million, sales to Pepco of $255 million, sales to DPL of $179 million and sales to ACE of $29 million in the Mid-Atlantic region, and sales to ComEd of $121 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2016, intersegment revenues for Generation include revenue from sales to PECO of $290 million and sales to BGE of $608 million in the Mid-Atlantic region, and sales to ComEd of $47 million in the Midwest region, which eliminate upon consolidation. For the Successor period of March 24, 2016 to December 31, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $295 million, sales to DPL of $154 million and sales to ACE of $37 million in the Mid-Atlantic region, which eliminate upon consolidation. For the year ended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and sales to BGE of $502 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation.revenues. |
| |
(b) | Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities. |
| |
(c) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 2423 — Supplemental Financial Information for additional information on total utility taxes for the years ended December 31, 2017, 2016 and 2015.taxes. |
| |
(d) | Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accountingauthoritative guidance. For Exelon, these amounts are included in operatingOperating revenues in the Consolidated Statements of Operations and Comprehensive Income. |
| |
(e) | Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2017. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the year ended December 31, 2015.2018. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Successor and Predecessor PHI:
| | | Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI | Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI |
Operating revenues(a): | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 - Successor | | | | | | | | | | | | |
Rate-regulated electric revenues | | $ | 2,239 |
| | $ | 1,151 |
| | $ | 1,236 |
| | $ | — |
| | $ | (17 | ) | | $ | 4,609 |
|
Rate-regulated natural gas revenues | | — |
| | 181 |
| | — |
| | — |
| | — |
| | 181 |
|
Shared service and other revenues | | — |
| | — |
| | — |
| | 435 |
| | (420 | ) | | 15 |
|
Total operating revenues | | $ | 2,239 |
| | $ | 1,332 |
| | $ | 1,236 |
| | $ | 435 |
| | $ | (437 | ) | | $ | 4,805 |
|
December 31, 2017 - Successor | | | | | | | | | | | | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 2,158 |
| | $ | 1,139 |
| | $ | 1,186 |
| | $ | — |
| | $ | (14 | ) | | $ | 4,469 |
| $ | 2,158 |
| | $ | 1,139 |
| | $ | 1,186 |
| | $ | — |
| | $ | (14 | ) | | $ | 4,469 |
|
Rate-regulated natural gas revenues | — |
| | 161 |
| | — |
| | — |
| | — |
| | 161 |
| — |
| | 161 |
| | — |
| | — |
| | — |
| | 161 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 52 |
| | (3 | ) | | 49 |
| — |
| | — |
| | — |
| | 52 |
| | (3 | ) | | 49 |
|
Total operating revenues | | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
| | $ | 52 |
| | $ | (17 | ) | | $ | 4,679 |
|
March 24, 2016 to December 31, 2016 - Successor | | | | | | | | | | | | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 1,675 |
| | $ | 850 |
| | $ | 989 |
| | $ | 5 |
| | $ | (13 | ) | | $ | 3,506 |
| $ | 1,675 |
| | $ | 850 |
| | $ | 989 |
| | $ | 5 |
| | $ | (13 | ) | | $ | 3,506 |
|
Rate-regulated natural gas revenues | — |
| | 92 |
| | — |
| | — |
| | — |
| | 92 |
| — |
| | 92 |
| | — |
| | — |
| | — |
| | 92 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | 45 |
| | — |
| | 45 |
| — |
| | — |
| | — |
| | 45 |
| | — |
| | 45 |
|
Total operating revenues | | $ | 1,675 |
| | $ | 942 |
| | $ | 989 |
| | $ | 50 |
| | $ | (13 | ) | | $ | 3,643 |
|
January 1, 2016 to March 23, 2016 - Predecessor | | | | | | | | | | | | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 511 |
| | $ | 279 |
| | $ | 268 |
| | $ | 42 |
| | $ | (4 | ) | | $ | 1,096 |
| $ | 511 |
| | $ | 279 |
| | $ | 268 |
| | $ | 42 |
| | $ | (4 | ) | | $ | 1,096 |
|
Rate-regulated natural gas revenues | — |
| | 56 |
| | — |
| | 1 |
| | — |
| | 57 |
| — |
| | 56 |
| | — |
| | 1 |
| | — |
| | 57 |
|
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
December 31, 2015 - Predecessor | | | | | | | | | | | | |
Rate-regulated electric revenues | $ | 2,129 |
| | $ | 1,138 |
| | $ | 1,295 |
| | $ | 210 |
| | $ | (2 | ) | | $ | 4,770 |
| |
Rate-regulated natural gas revenues | — |
| | 164 |
| | — |
| | 1 |
| | — |
| | 165 |
| |
Shared service and other revenues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| |
Total operating revenues | | $ | 511 |
| | $ | 335 |
| | $ | 268 |
| | $ | 43 |
| | $ | (4 | ) | | $ | 1,153 |
|
| | | | | | | | | | | | |
Intersegment revenues: | | | | | | | | | | | | | | | | | | | | | | |
December 31, 2018 - Successor | | $ | 6 |
| | $ | 8 |
| | $ | 3 |
| | $ | 435 |
| | $ | (437 | ) | | $ | 15 |
|
December 31, 2017 - Successor | $ | 6 |
| | $ | 8 |
| | $ | 2 |
| | $ | 53 |
| | $ | (19 | ) | | $ | 50 |
| 6 |
| | 8 |
| | 2 |
| | 53 |
| | (19 | ) | | 50 |
|
March 24, 2016 to December 31, 2016 - Successor | 4 |
| | 5 |
| | 2 |
| | 47 |
| | (13 | ) | | 45 |
| 4 |
| | 5 |
| | 2 |
| | 47 |
| | (13 | ) | | 45 |
|
January 1, 2016 to March 23, 2016 - Predecessor | | 1 |
| | 2 |
| | 1 |
| | — |
| | (4 | ) | | — |
|
Depreciation and amortization: | | | | | | | | | | | | |
December 31, 2018 - Successor | | $ | 385 |
| | $ | 182 |
| | $ | 136 |
| | $ | 37 |
| | $ | — |
| | $ | 740 |
|
December 31, 2017 - Successor | | 321 |
| | 167 |
| | 146 |
| | 42 |
| | (1 | ) | | $ | 675 |
|
March 24, 2016 to December 31, 2016 - Successor | | 224 |
| | 120 |
| | 128 |
| | 43 |
| | — |
| | $ | 515 |
|
January 1, 2016 to March 23, 2016 - Predecessor | | 71 |
| | 37 |
| | 37 |
| | 11 |
| | (4 | ) | | $ | 152 |
|
Operating expenses: | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 1,919 |
| | $ | 1,143 |
| | $ | 1,087 |
| | $ | 442 |
| | $ | (435 | ) | | $ | 4,156 |
|
December 31, 2017 - Successor | | 1,760 |
| | 1,071 |
| | 1,029 |
| | 68 |
| | (17 | ) | | $ | 3,911 |
|
March 24, 2016 to December 31, 2016 - Successor | | 1,577 |
| | 952 |
| | 1,000 |
| | 33 |
| | (13 | ) | | $ | 3,549 |
|
January 1, 2016 to March 23, 2016 - Predecessor | | 443 |
| | 284 |
| | 251 |
| | 73 |
| | (3 | ) | | $ | 1,048 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | January 1, 2016 to March 23, 2016 - Predecessor | 1 |
| | 2 |
| | 1 |
| | — |
| | (4 | ) | | — |
| |
December 31, 2015 - Predecessor | 5 |
| | 6 |
| | 4 |
| | — |
| | (15 | ) | | — |
| |
Depreciation and amortization: | | | | | | | | | | | | |
| | Pepco | | DPL | | ACE | | Other(b) | | Intersegment Eliminations | | PHI |
Interest expense, net: | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 128 |
| | $ | 58 |
| | $ | 64 |
| | $ | 11 |
| | $ | — |
| | $ | 261 |
|
December 31, 2017 - Successor | $ | 321 |
| | $ | 167 |
| | $ | 146 |
| | $ | 42 |
| | $ | (1 | ) | | $ | 675 |
| 121 |
| | 51 |
| | 61 |
| | 13 |
| | (1 | ) | | $ | 245 |
|
March 24, 2016 to December 31, 2016 - Successor | 224 |
| | 120 |
| | 128 |
| | 43 |
| | — |
| | $ | 515 |
| 98 |
| | 38 |
| | 47 |
| | 12 |
| | — |
| | $ | 195 |
|
January 1, 2016 to March 23, 2016 - Predecessor | 71 |
| | 37 |
| | 37 |
| | 11 |
| | (4 | ) | | $ | 152 |
| 29 |
| | 12 |
| | 15 |
| | 11 |
| | (2 | ) | | $ | 65 |
|
December 31, 2015 - Predecessor | 256 |
| | 148 |
| | 175 |
| | 45 |
| | — |
| | $ | 624 |
| |
Operating expenses: | | | | | | | | | | |
|
| |
Income (loss) before income taxes: | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 223 |
| | $ | 142 |
| | $ | 87 |
| | $ | 388 |
| | $ | (408 | ) | | $ | 432 |
|
December 31, 2017 - Successor | $ | 1,760 |
| | $ | 1,071 |
| | $ | 1,029 |
| | $ | 68 |
| | $ | (17 | ) | | $ | 3,911 |
| 310 |
| | 192 |
| | 103 |
| | 377 |
| | (404 | ) | | $ | 578 |
|
March 24, 2016 to December 31, 2016 - Successor | 1,577 |
| | 952 |
| | 1,000 |
| | 33 |
| | (13 | ) | | $ | 3,549 |
| 36 |
| | (30 | ) | | (51 | ) | | (84 | ) | | 71 |
| | $ | (58 | ) |
January 1, 2016 to March 23, 2016 - Predecessor | 443 |
| | 284 |
| | 251 |
| | 73 |
| | (3 | ) | | $ | 1,048 |
| 47 |
| | 43 |
| | 5 |
| | 59 |
| | (118 | ) | | $ | 36 |
|
December 31, 2015 - Predecessor | 1,790 |
| | 1,137 |
| | 1,161 |
| | 220 |
| | — |
| | $ | 4,308 |
| |
Interest expense, net: | | | | | | | | | | |
|
| |
Income taxes: | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 13 |
| | $ | 22 |
| | $ | 12 |
| | $ | (10 | ) | | $ | (2 | ) | | $ | 35 |
|
December 31, 2017 - Successor | $ | 121 |
| | $ | 51 |
| | $ | 61 |
| | $ | 13 |
| | $ | (1 | ) | | $ | 245 |
| 105 |
| | 71 |
| | 26 |
| | 15 |
| | — |
| | $ | 217 |
|
March 24, 2016 to December 31, 2016 - Successor | 98 |
| | 38 |
| | 47 |
| | 12 |
| | — |
| | $ | 195 |
| 26 |
| | 5 |
| | (5 | ) | | (23 | ) | | — |
| | $ | 3 |
|
January 1, 2016 to March 23, 2016 - Predecessor | 29 |
| | 12 |
| | 15 |
| | 11 |
| | (2 | ) | | $ | 65 |
| 15 |
| | 17 |
| | 1 |
| | (16 | ) | | — |
| | $ | 17 |
|
December 31, 2015 - Predecessor | 124 |
| | 50 |
| | 64 |
| | 43 |
| | (1 | ) | | $ | 280 |
| |
Income (loss) before income taxes: | | | | | | | | | | |
|
| |
Net income (loss): | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 210 |
| | $ | 120 |
| | $ | 75 |
| | $ | (22 | ) | | $ | 15 |
| | $ | 398 |
|
December 31, 2017 - Successor | $ | 310 |
| | $ | 192 |
| | $ | 103 |
| | $ | 377 |
| | $ | (404 | ) | | $ | 578 |
| 205 |
| | 121 |
| | 77 |
| | (91 | ) | | 50 |
| | $ | 362 |
|
March 24, 2016 to December 31, 2016 - Successor | 36 |
| | (30 | ) | | (51 | ) | | (84 | ) | | 71 |
| | $ | (58 | ) | 10 |
| | (35 | ) | | (47 | ) | | (34 | ) | | 45 |
| | $ | (61 | ) |
January 1, 2016 to March 23, 2016 - Predecessor | 47 |
| | 43 |
| | 5 |
| | 59 |
| | (118 | ) | | $ | 36 |
| 32 |
| | 26 |
| | 5 |
| | (44 | ) | | — |
| | $ | 19 |
|
December 31, 2015 - Predecessor | 289 |
| | 125 |
| | 73 |
| | 23 |
| | (29 | ) | | $ | 481 |
| |
Income taxes: | | | | | | | | | | |
|
| |
Capital expenditures: | | | | | | | | | | | |
|
|
December 31, 2018 - Successor | | $ | 656 |
| | $ | 364 |
| | $ | 335 |
| | $ | 20 |
| | $ | — |
| | $ | 1,375 |
|
December 31, 2017 - Successor | $ | 105 |
| | $ | 71 |
| | $ | 26 |
| | $ | 15 |
| | $ | — |
| | $ | 217 |
| 628 |
| | 428 |
| | 312 |
| | 28 |
| | — |
| | $ | 1,396 |
|
March 24, 2016 to December 31, 2016 - Successor | 26 |
| | 5 |
| | (5 | ) | | (23 | ) | | — |
| | $ | 3 |
| 489 |
| | 277 |
| | 218 |
| | 24 |
| | — |
| | 1,008 |
|
January 1, 2016 to March 23, 2016 - Predecessor | 15 |
| | 17 |
| | 1 |
| | (16 | ) | | — |
| | $ | 17 |
| 97 |
| | 72 |
| | 93 |
| | 11 |
| | — |
| | 273 |
|
December 31, 2015 - Predecessor | 102 |
| | 49 |
| | 33 |
| | (48 | ) | | 27 |
| | $ | 163 |
| |
Net income (loss): | | | | | | | | | | |
|
| |
Total assets: | | | | | | | | | | | | |
December 31, 2018 - Successor | | $ | 8,299 |
| | $ | 4,588 |
| | $ | 3,699 |
| | $ | 10,819 |
| | $ | (5,421 | ) | | $ | 21,984 |
|
December 31, 2017 - Successor | $ | 205 |
| | $ | 121 |
| | $ | 77 |
| | $ | (91 | ) | | $ | 50 |
| | $ | 362 |
| 7,832 |
| | 4,357 |
| | 3,445 |
| | 10,600 |
| | (4,987 | ) | | 21,247 |
|
March 24, 2016 to December 31, 2016 - Successor | 10 |
| | (35 | ) | | (47 | ) | | (34 | ) | | 45 |
| | $ | (61 | ) | |
January 1, 2016 to March 23, 2016 - Predecessor | 32 |
| | 26 |
| | 5 |
| | (44 | ) | | — |
| | $ | 19 |
| |
December 31, 2015 - Predecessor | 187 |
| | 76 |
| | 40 |
| | 25 |
| | (1 | ) | | $ | 327 |
| |
Capital expenditures: | | | | | | | | | | |
|
| |
December 31, 2017 - Successor | $ | 628 |
| | $ | 428 |
| | $ | 312 |
| | $ | 28 |
| | $ | — |
| | $ | 1,396 |
| |
March 24, 2016 to December 31, 2016 - Successor | 489 |
| | 277 |
| | 218 |
| | 24 |
| | — |
| | $ | 1,008 |
| |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | |
January 1, 2016 to March 23, 2016 - Predecessor | 97 |
| | 72 |
| | 93 |
| | 11 |
| | — |
| | 273 |
|
December 31, 2015 - Predecessor | 544 |
| | 352 |
| | 300 |
| | 34 |
| | — |
| | 1,230 |
|
Total assets: | | | | | | | | | | | |
December 31, 2017 - Successor | $ | 7,832 |
| | $ | 4,357 |
| | $ | 3,445 |
| | $ | 10,600 |
| | $ | (4,987 | ) | | $ | 21,247 |
|
December 31, 2016 - Successor | 7,335 |
| | 4,153 |
| | 3,457 |
| | 10,804 |
| | (4,724 | ) | | 21,025 |
|
__________
| |
(a) | Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses onin the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 2423 — Supplemental Financial Information for additional information on total utility taxes for the years ended December 31, 2017, 2016 and 2015.taxes. |
| |
(b) | Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger. |
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, total revenues:the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
| | | | | | | | | | | | | | | | | | | | | | 2018 |
| 2017 | | 2016 | | 2015 | Revenues from external customers(a) | | | | |
| Revenues from external customers(a) | | Intersegment revenues | | Total revenues | | Revenues from external customers(a) | | Intersegment revenues | | Total revenues | | Revenues from external customers(a) | | Intersegment revenues | | Total revenues | Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
Mid-Atlantic | $ | 5,515 |
|
| $ | 25 |
| | $ | 5,540 |
| | $ | 6,212 |
|
| $ | (33 | ) |
| $ | 6,179 |
| | $ | 5,974 |
|
| $ | (74 | ) | | $ | 5,900 |
| $ | 5,241 |
|
| $ | 233 |
| | $ | 5,474 |
| | $ | 13 |
|
| $ | 5,487 |
|
Midwest | 4,206 |
|
| (25 | ) | | 4,181 |
| | 4,402 |
|
| 10 |
|
| 4,412 |
| | 4,712 |
|
| (2 | ) | | 4,710 |
| 4,527 |
|
| 190 |
| | 4,717 |
| | (11 | ) |
| 4,706 |
|
New England | 2,010 |
|
| (8 | ) | | 2,002 |
| | 1,778 |
|
| (9 | ) |
| 1,769 |
| | 2,217 |
|
| (5 | ) | | 2,212 |
| 2,660 |
|
| 185 |
| | 2,845 |
| | (4 | ) |
| 2,841 |
|
New York | 1,535 |
|
| (17 | ) | | 1,518 |
| | 1,198 |
|
| (42 | ) |
| 1,156 |
| | 996 |
|
| (11 | ) | | 985 |
| 1,723 |
|
| (36 | ) | | 1,687 |
| | — |
|
| 1,687 |
|
ERCOT | 958 |
|
| 4 |
| | 962 |
| | 831 |
|
| 6 |
|
| 837 |
| | 863 |
|
| (6 | ) | | 857 |
| 572 |
|
| 560 |
| | 1,132 |
| | 1 |
|
| 1,133 |
|
Other Power Regions | 1,076 |
|
| (27 | ) | | 1,049 |
| | 969 |
|
| (62 | ) |
| 907 |
| | 1,182 |
|
| (80 | ) | | 1,102 |
| 870 |
|
| 686 |
| | 1,556 |
| | (62 | ) |
| 1,494 |
|
Total Revenues for Reportable Segments | $ | 15,300 |
|
| $ | (48 | ) | | $ | 15,252 |
| | $ | 15,390 |
|
| $ | (130 | ) |
| $ | 15,260 |
| | $ | 15,944 |
|
| $ | (178 | ) | | $ | 15,766 |
| |
Other (b) | 3,166 |
|
| 48 |
| | 3,214 |
| | 2,361 |
|
| 130 |
|
| 2,491 |
| | 3,191 |
|
| 178 |
| | 3,369 |
| |
Total Competitive Businesses Electric Revenues | | 15,593 |
|
| 1,818 |
| | 17,411 |
| | (63 | ) |
| 17,348 |
|
Competitive Businesses Natural Gas Revenues | | 1,524 |
|
| 1,194 |
| | 2,718 |
| | 62 |
|
| 2,780 |
|
Competitive Businesses Other Revenues(c) | | 510 |
| | (202 | ) | | 308 |
| | 1 |
| | 309 |
|
Total Generation Consolidated Operating Revenues | $ | 18,466 |
|
| $ | — |
| | $ | 18,466 |
| | $ | 17,751 |
|
| $ | — |
|
| $ | 17,751 |
| | $ | 19,135 |
|
| $ | — |
| | $ | 19,135 |
| 17,627 |
|
| 2,810 |
| | $ | 20,437 |
| | $ | — |
|
| $ | 20,437 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | |
| 2017 |
| Revenues from external customers(a) | | | | |
| Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
Mid-Atlantic | $ | 5,523 |
| | $ | (8 | ) | | $ | 5,515 |
| | $ | 25 |
| | $ | 5,540 |
|
Midwest | 3,923 |
| | 283 |
| | 4,206 |
| | (25 | ) | | 4,181 |
|
New England | 2,064 |
| | (54 | ) | | 2,010 |
| | (8 | ) | | 2,002 |
|
New York | 1,605 |
| | (38 | ) | | 1,567 |
| | (17 | ) | | 1,550 |
|
ERCOT | 641 |
| | 317 |
| | 958 |
| | 4 |
| | 962 |
|
Other Power Regions | 594 |
| | 482 |
| | 1,076 |
| | (27 | ) | | 1,049 |
|
Total Competitive Businesses Electric Revenues | 14,350 |
| | 982 |
| | 15,332 |
| | (48 | ) | | 15,284 |
|
Competitive Businesses Natural Gas Revenues | 1,658 |
| | 917 |
| | 2,575 |
| | 53 |
| | 2,628 |
|
Competitive Businesses Other Revenues(c) | 744 |
| | (151 | ) | | 593 |
| | (5 | ) | | 588 |
|
Total Generation Consolidated Operating Revenues | $ | 16,752 |
| | $ | 1,748 |
| | $ | 18,500 |
| | $ | — |
| | $ | 18,500 |
|
|
| | | | | | | | | | | | | | | | | | | |
| 2016 |
| Revenues from external customers(a) | | | | |
| Contracts with customers | | Other(b) | | Total | | Intersegment Revenues | | Total Revenues |
Mid-Atlantic | $ | 6,182 |
| | $ | 30 |
| | $ | 6,212 |
| | $ | (33 | ) | | $ | 6,179 |
|
Midwest | 4,007 |
| | 395 |
| | 4,402 |
| | 10 |
| | 4,412 |
|
New England | 1,953 |
| | (175 | ) | | 1,778 |
| | (9 | ) | | 1,769 |
|
New York | 1,198 |
| | 10 |
| | 1,208 |
| | (42 | ) | | 1,166 |
|
ERCOT | 810 |
| | 21 |
| | 831 |
| | 6 |
| | 837 |
|
Other Power Regions | 670 |
| | 299 |
| | 969 |
| | (62 | ) | | 907 |
|
Total Competitive Businesses Electric Revenues | 14,820 |
| | 580 |
| | 15,400 |
| | (130 | ) | | 15,270 |
|
Competitive Businesses Natural Gas Revenues | 1,953 |
| | 193 |
| | 2,146 |
| | 135 |
| | 2,281 |
|
Competitive Businesses Other Revenues(c) | 756 |
| | (545 | ) | | 211 |
| | (5 | ) | | 206 |
|
Total Generation Consolidated Operating Revenues | $ | 17,529 |
| | $ | 228 |
| | $ | 17,757 |
| | $ | — |
| | $ | 17,757 |
|
__________
| |
(a) | Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Includes revenues from derivatives and leases. |
| |
(c) | Other represents activities not allocated to a region. See text above for a description of included activities. Also includesIncludes a $38 million decrease to revenues, aand $52 million decrease to revenues, and a $7 million increase to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the years ended December 31,in 2017 2016, and 2015,2016, respectively, unrealized mark-to-market losses of $262 million, $131 million, losses ofand $500 million in 2018, 2017, and gains of $203 million for the years ended December 31, 2017, 2016, and 2015, respectively, and elimination of intersegment revenues. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation total revenuesRevenues net of purchased power and fuel expense:expense (Generation):
| | | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
| RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF | | RNF from external customers(a) | | Intersegment RNF | | Total RNF |
Mid-Atlantic | $ | 3,105 |
|
| $ | 109 |
| | $ | 3,214 |
| | $ | 3,282 |
|
| $ | 35 |
| | $ | 3,317 |
| | $ | 3,556 |
|
| $ | 15 |
| | $ | 3,571 |
| $ | 3,022 |
|
| $ | 51 |
| | $ | 3,073 |
| | $ | 3,105 |
|
| $ | 109 |
| | $ | 3,214 |
| | $ | 3,282 |
|
| $ | 35 |
| | $ | 3,317 |
|
Midwest | 2,810 |
|
| 10 |
| | 2,820 |
| | 2,969 |
|
| 2 |
| | 2,971 |
| | 2,912 |
|
| (20 | ) | | 2,892 |
| 3,112 |
|
| 23 |
| | 3,135 |
| | 2,810 |
|
| 10 |
| | 2,820 |
| | 2,969 |
|
| 2 |
| | 2,971 |
|
New England | 538 |
|
| (24 | ) | | 514 |
| | 467 |
|
| (29 | ) | | 438 |
| | 519 |
|
| (58 | ) | | 461 |
| 368 |
|
| (14 | ) | | 354 |
| | 538 |
|
| (24 | ) | | 514 |
| | 467 |
|
| (29 | ) | | 438 |
|
New York | 975 |
|
| 1 |
| | 976 |
| | 761 |
|
| (19 | ) | | 742 |
| | 584 |
|
| 50 |
| | 634 |
| 1,112 |
|
| 10 |
| | 1,122 |
| | 1,007 |
|
| 1 |
| | 1,008 |
| | 771 |
|
| (19 | ) | | 752 |
|
ERCOT | 575 |
|
| (243 | ) | | 332 |
| | 412 |
|
| (131 | ) | | 281 |
| | 425 |
|
| (132 | ) | | 293 |
| 501 |
|
| (243 | ) | | 258 |
| | 575 |
|
| (243 | ) | | 332 |
| | 412 |
|
| (131 | ) | | 281 |
|
Other Power Regions | 476 |
|
| (171 | ) | | 305 |
| | 483 |
|
| (147 | ) | | 336 |
| | 440 |
|
| (190 | ) | | 250 |
| 515 |
|
| (140 | ) | | 375 |
| | 476 |
|
| (171 | ) | | 305 |
| | 483 |
|
| (147 | ) | | 336 |
|
Total Revenues net of purchased power and fuel expense for Reportable Segments | $ | 8,479 |
|
| $ | (318 | ) | | $ | 8,161 |
| | $ | 8,374 |
|
| $ | (289 | ) | | $ | 8,085 |
| | $ | 8,436 |
|
| $ | (335 | ) | | $ | 8,101 |
| |
Total Revenues net of purchased power and fuel for Reportable Segments | | $ | 8,630 |
|
| $ | (313 | ) | | $ | 8,317 |
| | $ | 8,511 |
|
| $ | (318 | ) | | $ | 8,193 |
| | $ | 8,384 |
|
| $ | (289 | ) | | $ | 8,095 |
|
Other (b) | 297 |
|
| 318 |
| | 615 |
| | 547 |
|
| 289 |
| | 836 |
| | 678 |
|
| 335 |
| | 1,013 |
| 114 |
|
| 313 |
| | 427 |
| | 299 |
|
| 318 |
| | 617 |
| | 543 |
|
| 289 |
| | 832 |
|
Total Generation Revenues net of purchased power and fuel expense | $ | 8,776 |
|
| $ | — |
| | $ | 8,776 |
| | $ | 8,921 |
|
| $ | — |
| | $ | 8,921 |
| | $ | 9,114 |
|
| $ | — |
| | $ | 9,114 |
| $ | 8,744 |
|
| $ | — |
| | $ | 8,744 |
| | $ | 8,810 |
|
| $ | — |
| | $ | 8,810 |
| | $ | 8,927 |
|
| $ | — |
| | $ | 8,927 |
|
__________
| |
(a) | Includes purchases and sales fromfrom/to third parties and affiliated sales to the Utility Registrants. |
| |
(b) | Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million decrease in RNF, aand $57 million decrease in RNF, and a $8 million increase in RNF for the amortization of intangible assets and liabilities related to commodity contracts for the years ended December 31,in 2017 2016, and 2015,2016, respectively, unrealized mark-to-market losses of $319 million, $175 million, losses ofand $41 million in 2018, 2017, and gains of $257 million for the years ended December 31, 2017, 2016, and 2015, respectively, accelerated nuclear fuel amortization associated with the announced early retirement decision for Clinton and Quad Citiesplant retirements as discussed in Note 8 - Early Nuclear Plant Retirements of $57 million, $12 million and $60 million for the year ended December 31, 2018, 2017, and 2016 and the elimination of intersegment revenues net of purchased power and fuel expense.RNF. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
26.Electric and Gas Revenue by Customer Class (Utility Registrants):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2018 |
| | | | | | | Successor | | | | | | |
Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Rate-regulated electric revenues | | | | | | | | | | | | | |
Residential | $ | 2,942 |
| | $ | 1,566 |
| | $ | 1,382 |
| | $ | 2,351 |
| | $ | 1,021 |
| | $ | 669 |
| | $ | 661 |
|
Small commercial & industrial | 1,487 |
| | 404 |
| | 257 |
| | 488 |
| | 140 |
| | 186 |
| | 162 |
|
Large commercial & industrial | 538 |
| | 223 |
| | 429 |
| | 1,124 |
| | 846 |
| | 100 |
| | 178 |
|
Public authorities & electric railroads | 47 |
| | 28 |
| | 28 |
| | 58 |
| | 32 |
| | 14 |
| | 12 |
|
Other(a) | 867 |
| | 243 |
| | 327 |
| | 593 |
| | 193 |
| | 175 |
| | 227 |
|
Total rate-regulated electric revenues(b) | 5,881 |
| | 2,464 |
| | 2,423 |
| | 4,614 |
| | 2,232 |
| | 1,144 |
| | 1,240 |
|
Rate-regulated natural gas revenues | | | | | | | | | | | | | |
Residential | — |
| | 395 |
| | 491 |
| | 99 |
| | — |
| | 99 |
| | — |
|
Small commercial & industrial | — |
| | 143 |
| | 77 |
| | 44 |
| | — |
| | 44 |
| | — |
|
Large commercial & industrial | — |
| | 1 |
| | 124 |
| | 8 |
| | — |
| | 8 |
| | — |
|
Transportation | — |
| | 23 |
| | — |
| | 16 |
| | — |
| | 16 |
| | — |
|
Other(c) | — |
| | 6 |
| | 63 |
| | 13 |
| | — |
| | 13 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 568 |
| | 755 |
| | 180 |
| | — |
| | 180 |
| | — |
|
Total rate-regulated revenues from contracts with customers | 5,881 |
| | 3,032 |
| | 3,178 |
| | 4,794 |
| | 2,232 |
| | 1,324 |
| | 1,240 |
|
| | | | | | | | | | | | | |
Other revenues | | | | | | | | | | | | | |
Revenues from alternative revenue programs | (29 | ) | | (7 | ) | | (26 | ) | | — |
| | — |
| | 4 |
| | (4 | ) |
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 10 |
| | 7 |
| | 3 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
|
Total other revenues | 1 |
| | 6 |
| | (9 | ) | | 11 |
| | 7 |
| | 8 |
| | (4 | ) |
Total rate-regulated revenues for reportable segments | $ | 5,882 |
| | $ | 3,038 |
| | $ | 3,169 |
| | $ | 4,805 |
| | $ | 2,239 |
| | $ | 1,332 |
| | $ | 1,236 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 |
| | | | | | | Successor | | | | | | |
Revenues from contracts with customers | ComEd | | PECO | | BGE | | PHI | | Pepco | | DPL | | ACE |
Rate-regulated electric revenues | | | | | | | | | | | | | |
Residential | $ | 2,715 |
| | $ | 1,505 |
| | $ | 1,365 |
| | $ | 2,246 |
| | $ | 964 |
| | $ | 663 |
| | $ | 619 |
|
Small commercial & industrial | 1,363 |
| | 401 |
| | 254 |
| | 490 |
| | 137 |
| | 187 |
| | 166 |
|
Large commercial & industrial | 455 |
| | 223 |
| | 427 |
| | 1,086 |
| | 794 |
| | 103 |
| | 189 |
|
Public authorities & electric railroads | 44 |
| | 30 |
| | 31 |
| | 60 |
| | 33 |
| | 14 |
| | 13 |
|
Other(a) | 886 |
| | 204 |
| | 299 |
| | 541 |
| | 199 |
| | 163 |
| | 191 |
|
Total rate-regulated electric revenues(b) | 5,463 |
| | 2,363 |
| | 2,376 |
| | 4,423 |
| | 2,127 |
| | 1,130 |
| | 1,178 |
|
Rate-regulated natural gas revenues | | | | | | | | | | | | | |
Residential | — |
| | 331 |
| | 437 |
| | 90 |
| | — |
| | 90 |
| | — |
|
Small commercial & industrial | — |
| | 131 |
| | 75 |
| | 38 |
| | — |
| | 38 |
| | — |
|
Large commercial & industrial | — |
| | 1 |
| | 119 |
| | 8 |
| | — |
| | 8 |
| | — |
|
Transportation | — |
| | 23 |
| | — |
| | 15 |
| | — |
| | 15 |
| | — |
|
Other(c) | — |
| | 8 |
| | 28 |
| | 9 |
| | — |
| | 9 |
| | — |
|
Total rate-regulated natural gas revenues(d) | — |
| | 494 |
| | 659 |
| | 160 |
| | — |
| | 160 |
| | — |
|
Total rate-regulated revenues from contracts with customers | 5,463 |
| | 2,857 |
| | 3,035 |
| | 4,583 |
| | 2,127 |
| | 1,290 |
| | 1,178 |
|
| | | | | | | | | | | | | |
Other revenues | | | | | | | | | | | | | |
Revenues from alternative revenue programs | 43 |
| | — |
| | 124 |
| | 40 |
| | 26 |
| | 6 |
| | 8 |
|
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 8 |
| | 5 |
| | 3 |
| | — |
|
Other rate-regulated natural gas revenues(e) | — |
| | 1 |
| | 4 |
| | 1 |
| | — |
| | 1 |
| | — |
|
Other revenues(f) | — |
| | — |
| | — |
| | 47 |
| | — |
| | — |
| | — |
|
Total other revenues | 73 |
| | 13 |
| | 141 |
| | 96 |
| | 31 |
| | 10 |
| | 8 |
|
Total rate-regulated revenues for reportable segments | $ | 5,536 |
| | $ | 2,870 |
| | $ | 3,176 |
| | $ | 4,679 |
| | $ | 2,158 |
| | $ | 1,300 |
| | $ | 1,186 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Successor | | | Predecessor |
| 2016 | | March 24, 2016 to December 31, 2016 | | | January 1, 2016 to March 23, 2016 |
Revenues from contracts with customers | ComEd | | PECO | | BGE | | Pepco | | DPL | | ACE | | PHI | | | PHI |
Rate-regulated electric revenues | | | | | | | | | | | | | | | | |
Residential | $ | 2,603 |
| | $ | 1,631 |
| | $ | 1,504 |
| | $ | 1,004 |
| | $ | 672 |
| | $ | 664 |
| | $ | 1,779 |
| | | $ | 561 |
|
Small commercial & industrial | 1,318 |
| | 430 |
| | 276 |
| | 150 |
| | 188 |
| | 183 |
| | 400 |
| | | 121 |
|
Large commercial & industrial | 462 |
| | 234 |
| | 434 |
| | 790 |
| | 99 |
| | 201 |
| | 835 |
| | | 255 |
|
Public authorities & electric railroads | 45 |
| | 32 |
| | 35 |
| | 32 |
| | 13 |
| | 13 |
| | 45 |
| | | 13 |
|
Other(a) | 820 |
| | 192 |
| | 276 |
| | 190 |
| | 160 |
| | 187 |
| | 400 |
| | | 169 |
|
Total rate-regulated electric revenues(b) | 5,248 |
| | 2,519 |
| | 2,525 |
| | 2,166 |
| | 1,132 |
| | 1,248 |
| | 3,459 |
| | | 1,119 |
|
Rate-regulated natural gas revenues | | | | | | | | | | | | | | | | |
Residential | — |
| | 309 |
| | 432 |
| | — |
| | 86 |
| | — |
| | 50 |
| | | 36 |
|
Small commercial & industrial | — |
| | 121 |
| | 66 |
| | — |
| | 35 |
| | — |
| | 21 |
| | | 14 |
|
Large commercial & industrial | — |
| | — |
| | 114 |
| | — |
| | 6 |
| | — |
| | 4 |
| | | 2 |
|
Transportation | — |
| | 24 |
| | — |
| | — |
| | 13 |
| | — |
| | 10 |
| | | 3 |
|
Other(c) | — |
| | 9 |
| | 28 |
| | — |
| | 8 |
| | — |
| | 7 |
| | | 2 |
|
Total rate-regulated natural gas revenues(d) | — |
| | 463 |
| | 640 |
| | — |
| | 148 |
| | — |
| | 92 |
| | | 57 |
|
Total rate-regulated revenues from contracts with customers | 5,248 |
| | 2,982 |
| | 3,165 |
| | 2,166 |
| | 1,280 |
| | 1,248 |
| | 3,551 |
| | | 1,176 |
|
| | | | | | | | | | | | | | | | |
Other revenues | | | | | | | | | | | | | | | | |
Revenues from alternative revenue programs | (24 | ) | | — |
| | 53 |
| | 14 |
| | (6 | ) | | 9 |
| | 43 |
| | | (26 | ) |
Other rate-regulated electric revenues(e) | 30 |
| | 12 |
| | 13 |
| | 6 |
| | 3 |
| | — |
| | 6 |
| | | 3 |
|
Other rate-regulated natural gas revenues(e) | — |
| | — |
| | 2 |
| | — |
| | — |
| | — |
| | — |
| | | — |
|
Other revenues(f) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 43 |
| | | — |
|
Total other revenues | 6 |
| | 12 |
| | 68 |
| | 20 |
| | (3 | ) | | 9 |
| | 92 |
| | | (23 | ) |
Total rate-regulated revenues for reportable segments | $ | 5,254 |
| | $ | 2,994 |
| | $ | 3,233 |
| | $ | 2,186 |
| | $ | 1,277 |
| | $ | 1,257 |
| | $ | 3,643 |
| | | $ | 1,153 |
|
__________
| |
(a) | Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue. |
| |
(b) | Includes operating revenues from affiliates of $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018, $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2017, and $15 million, $7 million, $7 million, $2 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2016. |
| |
(c) | Includes revenues from off-system natural gas sales. |
| |
(d) | Includes operating revenues from affiliates of $1 million and $21 million at PECO and BGE, respectively, in 2018, $1 million and $11 million at PECO and BGE, respectively, in 2017, and $1 million and $14 million at PECO and BGE, respectively, in 2016. |
| |
(e) | Includes late payment charge revenues. |
| |
(f) | Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
25. Related Party Transactions (All Registrants)
Exelon
The financial statements of Exelon include related party transactions as presented in the tables below:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | | | | | | |
Generation (a) | | (2 | ) | | — |
| |
|
|
PECO (a) | $ | 1 |
|
| $ | 1 |
|
| $ | 1 |
| — |
|
| 1 |
|
| 1 |
|
BGE (a) | 4 |
|
| 4 |
|
| 4 |
| — |
|
| 4 |
|
| 4 |
|
ACE (a) | | — |
| | — |
| | — |
|
Other | 2 |
| | 5 |
| | 4 |
| 1 |
| | 2 |
| | 5 |
|
Total operating revenues from affiliates | $ | 7 |
| | $ | 10 |
| | $ | 9 |
| $ | (1 | ) | | $ | 7 |
| | $ | 10 |
|
Interest expense to affiliates, net: | | | | | | | | | | |
ComEd Financing III | $ | 14 |
| | $ | 13 |
| | $ | 13 |
| $ | 13 |
| | $ | 14 |
| | $ | 13 |
|
PECO Trust III | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
PECO Trust IV | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
BGE Capital Trust II | 10 |
| | 16 |
| | 16 |
| — |
| | 10 |
| | 16 |
|
Total interest expense to affiliates, net | $ | 36 |
| | $ | 41 |
| | $ | 41 |
| $ | 25 |
| | $ | 36 |
| | $ | 41 |
|
Earnings (losses) in equity method investments: | | | | | | | | | | |
Qualifying facilities and domestic power projects | $ | (33 | ) | | $ | (25 | ) | | $ | (8 | ) | $ | (29 | ) | | $ | (33 | ) | | $ | (25 | ) |
Other | 1 |
| | 1 |
| | 1 |
| 1 |
| | 1 |
| | 1 |
|
Total losses in equity method investments | $ | (32 | ) | | $ | (24 | ) | | $ | (7 | ) | $ | (28 | ) | | $ | (32 | ) | | $ | (24 | ) |
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Payables to affiliates (current): | | | | | | |
ComEd Financing III | $ | 4 |
| | $ | 4 |
| $ | 4 |
| | $ | 4 |
|
PECO Trust III | 1 |
| | 1 |
| 1 |
| | 1 |
|
BGE Capital Trust II | — |
| | 3 |
| |
Total payables to affiliates (current) | $ | 5 |
| | $ | 8 |
| $ | 5 |
| | $ | 5 |
|
Long-term debt due to financing trusts: | | | | |
Long-term debt to financing trusts: | | | | |
ComEd Financing III | $ | 205 |
| | $ | 205 |
| $ | 206 |
| | $ | 205 |
|
PECO Trust III | 81 |
| | 81 |
| 81 |
| | 81 |
|
PECO Trust IV | 103 |
| | 103 |
| 103 |
| | 103 |
|
BGE Capital Trust II | — |
| | 252 |
| |
Total long-term debt due to financing trusts | $ | 389 |
| | $ | 641 |
| |
Total long-term debt to financing trusts | | $ | 390 |
| | $ | 389 |
|
__________
| |
(a) | The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accountingauthoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 3—4—Regulatory Matters for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Transactions involving Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are further described in the tables below.
Generation
The financial statements of Generation include related party transactions as presented in the tables below:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | | | | | | |
ComEd (a) | $ | 121 |
|
| $ | 47 |
|
| $ | 18 |
| $ | 523 |
|
| $ | 121 |
|
| $ | 47 |
|
PECO (b) | 138 |
|
| 290 |
|
| 224 |
| 128 |
|
| 138 |
|
| 290 |
|
BGE (c) | 388 |
|
| 608 |
|
| 502 |
| 260 |
|
| 388 |
|
| 608 |
|
Pepco (d) | 255 |
| | 295 |
| | — |
| 206 |
| | 255 |
| | 295 |
|
DPL (e) | 179 |
| | 154 |
| | — |
| 120 |
| | 179 |
| | 154 |
|
ACE (f) | 29 |
| | 37 |
| | — |
| 29 |
| | 29 |
| | 37 |
|
BSC | 1 |
|
| 2 |
|
| 1 |
| 2 |
|
| 1 |
|
| 2 |
|
Other | 4 |
| | 6 |
| | 4 |
| — |
| | 4 |
| | 6 |
|
Total operating revenues from affiliates | $ | 1,115 |
| | $ | 1,439 |
| | $ | 749 |
| $ | 1,268 |
| | $ | 1,115 |
| | $ | 1,439 |
|
Purchased power and fuel from affiliates: | | | | | | | | | | |
ComEd | $ | 13 |
| | $ | — |
| | $ | — |
| $ | (6 | ) | | $ | 13 |
| | $ | — |
|
BGE | 9 |
| | 12 |
| | 14 |
| 20 |
| | 9 |
| | 12 |
|
Other | (3 | ) | | — |
| | — |
| — |
| | (3 | ) | | — |
|
Total purchased power and fuel from affiliates | $ | 19 |
| | $ | 12 |
| | $ | 14 |
| $ | 14 |
| | $ | 19 |
| | $ | 12 |
|
Operating and maintenance from affiliates: | | | | | | | | | | |
ComEd (g) | $ | 7 |
| | $ | 7 |
| | $ | 4 |
| $ | 7 |
| | $ | 7 |
| | $ | 7 |
|
PECO (g) | 1 |
| | 3 |
| | 2 |
| 2 |
| | 1 |
| | 3 |
|
BGE (g) | 1 |
| | 1 |
| | — |
| 2 |
| | 1 |
| | 1 |
|
Pepco | — |
| | 1 |
| | — |
| 1 |
| | — |
| | 1 |
|
PHISCO | 1 |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
|
BSC (h) | 689 |
| | 650 |
| | 614 |
| 652 |
| | 689 |
| | 650 |
|
Other | $ | (2 | ) | | $ | — |
| | $ | — |
| (4 | ) | | (2 | ) | | — |
|
Total operating and maintenance from affiliates | $ | 697 |
| | $ | 663 |
| | $ | 620 |
| $ | 661 |
| | $ | 697 |
| | $ | 663 |
|
Interest expense to affiliates, net: | | | | | | | | | | |
Exelon Corporate (i) | $ | 37 |
| | $ | 39 |
| | $ | 43 |
| $ | 36 |
| | $ | 37 |
| | $ | 39 |
|
PCI | 1 |
| | — |
| | — |
| — |
| | 1 |
| | — |
|
PECO | 1 |
| | — |
| | — |
| — |
| | 1 |
| | — |
|
Total interest expense to affiliates, net: | 39 |
| | 39 |
| | 43 |
| $ | 36 |
| | $ | 39 |
| | $ | 39 |
|
Earnings (losses) in equity method investments | | | | | | | | | | |
Qualifying facilities and domestic power projects | $ | (33 | ) | | $ | (25 | ) | | $ | (8 | ) | $ | (30 | ) | | $ | (33 | ) | | $ | (25 | ) |
Capitalized costs | | | | | | | | | | |
BSC (h) | $ | 98 |
| | $ | 98 |
| | $ | 76 |
| $ | 67 |
| | $ | 98 |
| | $ | 98 |
|
Cash distribution paid to member | $ | 659 |
| | $ | 922 |
| | $ | 2,474 |
| |
Contribution from member | $ | 102 |
| | $ | 142 |
| | $ | 47 |
| |
Cash distributions paid to member | | $ | 1,001 |
| | $ | 659 |
| | $ | 922 |
|
Contributions from member | | $ | 155 |
| | $ | 102 |
| | $ | 142 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Receivables from affiliates (current): | | | | | | |
ComEd (a) | $ | 28 |
| | $ | 14 |
| $ | 69 |
| | $ | 28 |
|
PECO (b) | 26 |
| | 33 |
| 30 |
| | 26 |
|
BGE (c) | 24 |
| | 26 |
| 24 |
| | 24 |
|
Pepco (d) | 36 |
| | 44 |
| 28 |
| | 36 |
|
DPL (e) | 12 |
| | 16 |
| 7 |
| | 12 |
|
ACE (f) | 6 |
| | 9 |
| 5 |
| | 6 |
|
PHISCO (h) | 1 |
| | 5 |
| — |
| | 1 |
|
PCI | — |
| | 8 |
| |
Other | 7 |
| | 1 |
| 10 |
| | 7 |
|
Total receivables from affiliates (current) | $ | 140 |
| | $ | 156 |
| $ | 173 |
| | $ | 140 |
|
Intercompany money pool (current): | | | | | | |
Exelon Corporate | | $ | 100 |
| | $ | — |
|
PCI | $ | 54 |
| | $ | 55 |
| — |
| | 54 |
|
Total intercompany money pool (current) | | $ | 100 |
| | $ | 54 |
|
Payables to affiliates (current): | | | | | | |
Exelon Corporate (i) | $ | 21 |
| | $ | 22 |
| $ | 17 |
| | $ | 21 |
|
BSC (h) | 74 |
| | 99 |
| 95 |
| | 74 |
|
ComEd | 12 |
| | 9 |
| 19 |
| | 12 |
|
PECO (b) | 4 |
| | — |
| — |
| | 4 |
|
Other | 12 |
| | 7 |
| 8 |
| | 12 |
|
Total payables to affiliates (current) | $ | 123 |
| | $ | 137 |
| $ | 139 |
| | $ | 123 |
|
Long-term debt due to affiliates (noncurrent): | | | | |
Other liabilities to affiliates (current): | | | | |
ComEd (a) | | $ | 14 |
| | $ | — |
|
Long-term debt to affiliates (noncurrent): | | | | |
Exelon Corporate (k) | $ | 910 |
| | $ | 922 |
| $ | 898 |
| | $ | 910 |
|
Payables to affiliates (noncurrent): | | | | | | |
BSC (h) | $ | — |
| | $ | 1 |
| |
ComEd (j) | 2,528 |
| | 2,169 |
| $ | 2,217 |
| | $ | 2,528 |
|
PECO (j) | 537 |
| | 438 |
| 389 |
| | 537 |
|
Total payables to affiliates (noncurrent) | $ | 3,065 |
| | $ | 2,608 |
| $ | 2,606 |
| | $ | 3,065 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
| |
(a) | Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information. |
| |
(b) | Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. See Note 3—Regulatory Matters for additional information. |
| |
(c) | Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information. |
| |
(d) | Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. See Note 3—Regulatory Matters for additional information. |
| |
(e) | Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information. |
| |
(f) | Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. See Note 3—Regulatory Matters for additional information. |
| |
(g) | Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations. |
| |
(h) | Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(i) | The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation. |
| |
(j) | Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations.Obligations for additional information. |
| |
(k) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate onaffiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation onin Exelon’s Consolidated Balance Sheets. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd
The financial statements of ComEd include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating revenues from affiliates | | | | | |
Generation | $ | 9 |
|
| $ | 7 |
|
| $ | 4 |
|
BSC | 6 |
| | 6 |
| | — |
|
PECO | — |
| | 1 |
| | — |
|
BGE | — |
| | 1 |
| | — |
|
Total operating revenues from affiliates | $ | 15 |
| | $ | 15 |
| | $ | 4 |
|
Purchased power from affiliate | | | | | |
Generation (a) | $ | 108 |
| | $ | 47 |
| | $ | 18 |
|
Operating and maintenance from affiliates | | | | | |
BSC (b) | $ | 270 |
| | $ | 225 |
| | $ | 195 |
|
PECO | — |
| | 1 |
| | — |
|
BGE | — |
| | 1 |
| | — |
|
Total operating and maintenance from affiliates | $ | 270 |
| | $ | 227 |
| | $ | 195 |
|
Interest expense to affiliates, net: | | | | | |
ComEd Financing III | $ | 13 |
| | $ | 13 |
| | $ | 13 |
|
Capitalized costs | | | | | |
BSC (b) | $ | 118 |
| | $ | 112 |
| | $ | 103 |
|
Cash dividends paid to parent | $ | 422 |
| | $ | 369 |
| | $ | 299 |
|
Contribution from parent | $ | 651 |
| | $ | 315 |
| | $ | 202 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenues from affiliates | | | | | |
Generation | $ | 9 |
|
| $ | 9 |
|
| $ | 7 |
|
BSC | 7 |
| | 6 |
| | 6 |
|
PECO | 10 |
| | — |
| | 1 |
|
BGE | 1 |
| | — |
| | 1 |
|
Total operating revenues from affiliates | $ | 27 |
| | $ | 15 |
| | $ | 15 |
|
Purchased power from affiliates | | | | | |
Generation (a) | $ | 529 |
| | $ | 108 |
| | $ | 47 |
|
Operating and maintenance from affiliates | | | | | |
BSC (b) | $ | 265 |
| | $ | 270 |
| | $ | 225 |
|
PECO | 1 |
| | — |
| | 1 |
|
BGE | 1 |
| | — |
| | 1 |
|
Total operating and maintenance from affiliates | $ | 267 |
| | $ | 270 |
| | $ | 227 |
|
Interest expense to affiliates, net: | | | | | |
ComEd Financing III | $ | 13 |
| | $ | 13 |
| | $ | 13 |
|
Capitalized costs | | | | | |
BSC (b) | $ | 135 |
| | $ | 118 |
| | $ | 112 |
|
Cash dividends paid to parent | $ | 459 |
| | $ | 422 |
| | $ | 369 |
|
Contributions from parent | $ | 500 |
| | $ | 651 |
| | $ | 315 |
|
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Prepaid voluntary employee beneficiary association trust (c) | $ | 2 |
| | $ | 5 |
| $ | 5 |
| | $ | 2 |
|
Receivable from affiliates (current): | | | | |
Receivables from affiliates (current): | | | | |
Voluntary employee beneficiary association trust | $ | 1 |
| | $ | 2 |
| $ | 1 |
| | $ | 1 |
|
Generation | 12 |
| | 9 |
| 19 |
| | 12 |
|
Exelon Corporate (d) | — |
| | 345 |
| |
Total receivable from affiliates (current) | $ | 13 |
| | $ | 356 |
| |
Receivable from affiliates (noncurrent): | | | | |
Generation (e) | $ | 2,528 |
| | $ | 2,169 |
| |
Other | — |
| | 1 |
| |
Total receivable from affiliates (noncurrent) | $ | 2,528 |
| | $ | 2,170 |
| |
Total receivables from affiliates (current) | | $ | 20 |
| | $ | 13 |
|
Receivables from affiliates (noncurrent): | | | | |
Generation (d) | | $ | 2,217 |
| | $ | 2,528 |
|
Payables to affiliates (current): | | | | | | |
Generation (a) | $ | 28 |
| | $ | 14 |
| $ | 55 |
| | $ | 28 |
|
BSC (b) | 39 |
| | 42 |
| 56 |
| | 39 |
|
ComEd Financing III | 4 |
| | 4 |
| 4 |
| | 4 |
|
PECO | — |
| | 2 |
| |
Exelon Corporate | 3 |
| | 3 |
| 4 |
| | 3 |
|
Total payables to affiliates (current) | $ | 74 |
| | $ | 65 |
| $ | 119 |
| | $ | 74 |
|
Long-term debt to ComEd financing trust | | | | |
Long-term debt to ComEd financing trust: | | | | |
ComEd Financing III | $ | 205 |
| | $ | 205 |
| $ | 205 |
| | $ | 205 |
|
__________
| |
(a) | ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets. |
| |
(d) | Represents indemnification from Exelon Corporate related to the like-kind exchange. |
| |
(e) | ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO
The financial statements of PECO include related party transactions as presented in the tables below:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | | | | | | |
Generation (a) | $ | 1 |
|
| $ | 3 |
|
| $ | 2 |
| $ | 2 |
|
| $ | 1 |
|
| $ | 3 |
|
BSC | 5 |
| | 3 |
| | — |
| 3 |
| | 5 |
| | 3 |
|
ComEd | — |
| | 1 |
| | — |
| 1 |
| | — |
| | 1 |
|
BGE | 1 |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
|
ACE | | 1 |
| | — |
| | — |
|
Total operating revenues from affiliates | $ | 7 |
| | $ | 8 |
| | $ | 2 |
| $ | 8 |
| | $ | 7 |
| | $ | 8 |
|
Purchased power from affiliate | | | | | | |
Purchased power from affiliates | | | | | | |
Generation (b) | $ | 135 |
| | $ | 287 |
| | $ | 220 |
| $ | 126 |
| | $ | 135 |
| | $ | 287 |
|
Operating and maintenance from affiliates: | | | | | | | | | | |
BSC (c) | $ | 146 |
| | $ | 142 |
| | $ | 107 |
| $ | 146 |
| | $ | 146 |
| | $ | 142 |
|
Generation | 2 |
| | 2 |
| | 3 |
| 2 |
| | 2 |
| | 2 |
|
ComEd
| — |
| | 1 |
| | — |
| 7 |
| | — |
| | 1 |
|
BGE | 1 |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
|
Total operating and maintenance from affiliates | $ | 149 |
| | $ | 146 |
| | $ | 110 |
| $ | 156 |
| | $ | 149 |
| | $ | 146 |
|
Interest expense to affiliates, net: | | | | | | | | | | |
PECO Trust III | $ | 6 |
| | $ | 6 |
| | $ | 6 |
| $ | 6 |
| | $ | 6 |
| | $ | 6 |
|
PECO Trust IV | 6 |
| | 6 |
| | 6 |
| 6 |
| | 6 |
| | 6 |
|
Exelon Corporate
| | 2 |
| | — |
| | — |
|
Generation | (1 | ) | | — |
| | — |
| — |
| | (1 | ) | | — |
|
Total interest expense to affiliates, net: | $ | 11 |
| | $ | 12 |
| | $ | 12 |
| $ | 14 |
| | $ | 11 |
| | $ | 12 |
|
Capitalized costs | | | | | | | | | | |
BSC (c) | $ | 59 |
| | $ | 57 |
| | $ | 40 |
| $ | 64 |
| | $ | 59 |
| | $ | 57 |
|
Cash dividends paid to parent | $ | 288 |
| | $ | 277 |
| | $ | 279 |
| $ | 306 |
| | $ | 288 |
| | $ | 277 |
|
Contribution from parent | $ | 16 |
| | $ | 18 |
| | $ | 16 |
| |
Contributions from parent | | $ | 89 |
| | $ | 16 |
| | $ | 18 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Prepaid voluntary employee beneficiary association trust (d) | $ | — |
| | $ | 1 |
| $ | 1 |
| | $ | — |
|
Receivable from affiliate (current): | | | | |
ComEd | $ | — |
| | $ | 2 |
| |
BGE | — |
| | 2 |
| |
Total receivable from affiliates (current) | $ | — |
| | $ | 4 |
| |
Receivable from affiliate (noncurrent): | | | | |
Receivables from affiliates (noncurrent): | | | | |
Generation (e) | $ | 537 |
| | $ | 438 |
| $ | 389 |
| | $ | 537 |
|
Payables to affiliates (current): | | | | | | |
Generation (b) | $ | 22 |
| | $ | 33 |
| $ | 30 |
| | $ | 22 |
|
BSC (c) | 29 |
| | 28 |
| 26 |
| | 29 |
|
Exelon Corporate | 1 |
| | 1 |
| 2 |
| | 1 |
|
PECO Trust III | 1 |
| | 1 |
| 1 |
| | 1 |
|
Total payables to affiliates (current) | $ | 53 |
| | $ | 63 |
| $ | 59 |
| | $ | 53 |
|
Long-term debt to financing trusts: | | | | | | |
PECO Trust III | $ | 81 |
| | $ | 81 |
| $ | 81 |
| | $ | 81 |
|
PECO Trust IV | 103 |
| | 103 |
| 103 |
| | 103 |
|
Total long-term debt to financing trusts | $ | 184 |
| | $ | 184 |
| $ | 184 |
| | $ | 184 |
|
__________
| |
(a) | PECO provides energy to Generation for Generation’s own use. |
| |
(b) | PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs. |
| |
(c) | PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(d) | The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. |
| |
(e) | PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
The financial statements of BGE include related party transactions as presented in the tables below:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | | | | | | |
Generation (a) | $ | 10 |
|
| $ | 13 |
|
| $ | 14 |
| $ | 22 |
|
| $ | 10 |
|
| $ | 13 |
|
BSC | 5 |
| | 6 |
| | — |
| 5 |
| | 5 |
| | 6 |
|
ComEd | — |
| | 1 |
| | — |
| 1 |
| | — |
| | 1 |
|
PECO | 1 |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
|
Total operating revenues from affiliates | $ | 16 |
| | $ | 21 |
| | $ | 14 |
| $ | 29 |
| | $ | 16 |
| | $ | 21 |
|
Purchased power from affiliate | | | | | | |
Purchased power from affiliates | | | | | | |
Generation (b) | $ | 384 |
| | $ | 604 |
| | $ | 498 |
| $ | 257 |
| | $ | 384 |
| | $ | 604 |
|
Operating and maintenance from affiliates: | | | | | | | | | | |
BSC (c) | $ | 152 |
| | $ | 130 |
| | $ | 118 |
| $ | 157 |
| | $ | 152 |
| | $ | 130 |
|
Generation | | 3 |
| | — |
| | — |
|
ComEd | — |
| | 1 |
| | — |
| 1 |
| | — |
| | 1 |
|
PECO | 1 |
| | 1 |
| | — |
| 1 |
| | 1 |
| | 1 |
|
Total operating and maintenance from affiliates | $ | 153 |
| | $ | 132 |
| | $ | 118 |
| $ | 162 |
| | $ | 153 |
| | $ | 132 |
|
Interest expense to affiliates, net: | | | | | | | | | | |
BGE Capital Trust II | $ | 10 |
| | $ | 16 |
| | $ | 16 |
| $ | — |
| | $ | 10 |
| | $ | 16 |
|
Capitalized costs | | | | | | | | | | |
BSC (c) | $ | 54 |
| | $ | 36 |
| | $ | 28 |
| $ | 79 |
| | $ | 54 |
| | $ | 36 |
|
Cash dividends paid to parent | $ | 198 |
| | $ | 179 |
| | $ | 158 |
| $ | 209 |
| | $ | 198 |
| | $ | 179 |
|
Contribution from parent | $ | 184 |
| | $ | 61 |
| | $ | 7 |
| |
Contributions from parent | | $ | 109 |
| | $ | 184 |
| | $ | 61 |
|
| | | December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Receivable from affiliates (current): | | | | |
Receivables from affiliates (current): | | | | |
Other | $ | 1 |
| | $ | — |
| $ | 1 |
| | $ | 1 |
|
Payables to affiliates (current): | | | | | | |
Generation (b) | $ | 24 |
| | $ | 26 |
| $ | 24 |
| | $ | 24 |
|
BSC (c) | 25 |
| | 22 |
| 38 |
| | 25 |
|
Exelon Corporate | 1 |
| | 1 |
| 2 |
| | 1 |
|
PECO | — |
| | 2 |
| |
BGE Capital Trust II | — |
| | 3 |
| |
Other | 2 |
| | 1 |
| 1 |
| | 2 |
|
Total payables to affiliates (current) | $ | 52 |
| | $ | 55 |
| $ | 65 |
| | $ | 52 |
|
Long-term debt to BGE financing trust | | | | |
BGE Capital Trust II | $ | — |
| | $ | 252 |
| |
__________
| |
(a) | BGE provides energy to Generation for Generation’s own use. |
| |
(b) | BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information. |
| |
(c) | BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
The financial statements of PHI include related party transactions as presented in the tables below:
| | | Successor | Successor |
| For the Year Ended December 31, | | March 24, 2016 to December 31, | For the Year Ended December 31, | | For the Year Ended December 31, | | March 24, 2016 to December 31, |
| 2017 | | 2016 | 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | | | | |
BSC | $ | 48 |
| | $ | 44 |
| $ | 12 |
| | $ | 48 |
| | $ | 44 |
|
PHISCO | 2 |
| | — |
| 1 |
| | 2 |
| | — |
|
Generation | — |
| | 1 |
| 2 |
| | — |
| | 1 |
|
Total operating revenues from affiliates | $ | 50 |
| | $ | 45 |
| $ | 15 |
| | $ | 50 |
| | $ | 45 |
|
Purchased power from affiliate | | | | |
Purchased power from affiliates | | | | | | |
Generation | $ | 463 |
| | $ | 486 |
| $ | 355 |
| | $ | 463 |
| | $ | 486 |
|
Operating and maintenance from affiliates: | | | | | | | | |
BSC(a) | $ | 145 |
| | $ | 86 |
| $ | 147 |
| | $ | 145 |
| | $ | 86 |
|
Other | 5 |
| | 3 |
| 5 |
| | 5 |
| | 3 |
|
Total operating and maintenance from affiliates | $ | 150 |
| | $ | 89 |
| $ | 152 |
| | $ | 150 |
| | $ | 89 |
|
Earnings (losses) in equity method investments: | | | | | | |
Other | | $ | 1 |
| | $ | — |
| | $ | — |
|
Capitalized costs: | | | | | | |
BSC (a) | | $ | 102 |
| | $ | — |
| | $ | — |
|
PHISCO (a) | | 79 |
| | — |
| | — |
|
Total capitalized costs | | $ | 181 |
| | $ | — |
| | $ | — |
|
Cash dividends paid to parent | $ | 311 |
| | $ | 273 |
| $ | 326 |
| | $ | 311 |
| | $ | 273 |
|
Contribution from member | $ | 758 |
| | $ | 1,251 |
| |
Contributions from parent | | $ | 385 |
| | $ | 758 |
| | $ | 1,251 |
|
| | | Successor | | | | | |
| December 31, | December 31, |
| 2017 | | 2016 | 2018 | | 2017 |
Payables to affiliates (current): | | | | | | |
Generation | $ | 54 |
| | $ | 74 |
| $ | 40 |
| | $ | 54 |
|
BGE | 1 |
| | — |
| — |
| | 1 |
|
BSC(a) | 24 |
| | 10 |
| 41 |
| | 24 |
|
Exelon Corporate | 6 |
| | 6 |
| 6 |
| | 6 |
|
Other | 5 |
| | 4 |
| 7 |
| | 5 |
|
Total payables to affiliates (current) | $ | 90 |
| | $ | 94 |
| $ | 94 |
| | $ | 90 |
|
__________
| |
(a) | PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
The financial statements of Pepco include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating revenues from affiliates: | | | | | |
Generation (a) | $ | — |
| | $ | 1 |
| | $ | — |
|
PHISCO | 6 |
| | 4 |
| | 5 |
|
Total operating revenues from affiliates | $ | 6 |
| | $ | 5 |
| | $ | 5 |
|
Purchased power from affiliate | | | | | |
Generation (b) | $ | 255 |
| | $ | 295 |
| | $ | — |
|
Operating and maintenance: | | | | | |
PHISCO (c) | $ | 219 |
| | $ | 263 |
| | $ | 240 |
|
PES (d) | 29 |
| | 39 |
| | 26 |
|
Total operating and maintenance | $ | 248 |
| | $ | 302 |
| | $ | 266 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (c) | $ | 53 |
| | $ | 31 |
| | $ | — |
|
PHISCO (c) | 5 |
| | 4 |
| | 4 |
|
Total operating and maintenance from affiliates | $ | 58 |
| | $ | 35 |
| | $ | 4 |
|
Cash dividends paid to parent | $ | 133 |
| | $ | 136 |
| | $ | 146 |
|
Contribution from parent | $ | 161 |
| | $ | 187 |
| | $ | 112 |
|
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Payables to affiliates (current): | | | |
Generation (b) | $ | 36 |
| | $ | 44 |
|
BSC (c) | 11 |
| | 4 |
|
DPL | — |
| | 1 |
|
PHISCO (c) | 27 |
| | 25 |
|
Total payables to affiliates (current) | $ | 74 |
| | $ | 74 |
|
__________
| |
(a) | Pepco provides energy to Generation for Generation’s own use.
|
| |
(b) | Pepco procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information. |
| |
(c) | Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(d) | PES performs underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL
The financial statements of DPL include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating revenues from affiliates: | | | | | |
PHISCO | $ | 6 |
| | $ | 5 |
| | $ | 5 |
|
Other | 2 |
| | 2 |
| | 1 |
|
Total operating revenues from affiliates | $ | 8 |
| | $ | 7 |
| | $ | 6 |
|
Purchased power from affiliate | | | | | |
Generation (a) | $ | 179 |
| | $ | 154 |
| | $ | — |
|
Operating and maintenance: | | | | | |
PHISCO (b) | $ | 165 |
| | $ | 194 |
| | $ | 179 |
|
PES (c) | 9 |
| | 8 |
| | 3 |
|
Total operating and maintenance | $ | 174 |
| | $ | 202 |
| | $ | 182 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 31 |
| | $ | 18 |
| | $ | — |
|
Other | 1 |
| | 1 |
| | 1 |
|
Total operating and maintenance from affiliates | $ | 32 |
| | $ | 19 |
| | $ | 1 |
|
Cash dividends paid to parent | $ | 112 |
| | $ | 54 |
| | $ | 92 |
|
Contribution from parent | $ | — |
| | $ | 152 |
| | $ | 75 |
|
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Receivables from affiliates (current): | | | |
Pepco | $ | — |
| | $ | 1 |
|
ACE | — |
| | 2 |
|
Total receivable from affiliates (current) | $ | — |
| | $ | 3 |
|
Payables to affiliates (current): | | | |
Generation (a) | $ | 12 |
| | $ | 16 |
|
BSC (b) | 7 |
| | 3 |
|
PHISCO (b) | 27 |
| | 19 |
|
Total payables to affiliates (current) | $ | 46 |
| | $ | 38 |
|
__________
| |
(a) | DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information. |
| |
(b) | DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | PES performs underground transmission construction services, including services that are treated as capital costs, for DPL. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ACE
The financial statements of ACE include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2017 | | 2016 | | 2015 |
Operating revenues from affiliates: | | | | | |
PHISCO | $ | 1 |
| | $ | 2 |
| | $ | 2 |
|
Other | 1 |
| | 1 |
| | 2 |
|
Total operating revenues from affiliates | $ | 2 |
| | $ | 3 |
| | $ | 4 |
|
Purchased power from affiliate | | | | | |
Generation (a) | $ | 29 |
| | $ | 37 |
| | $ | — |
|
Operating and maintenance: | | | | | |
PHISCO (b) | $ | 135 |
| | $ | 155 |
| | $ | 143 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 25 |
| | $ | 15 |
| | $ | — |
|
Other | 3 |
| | 3 |
| | 3 |
|
Total operating and maintenance from affiliates | $ | 28 |
| | $ | 18 |
| | $ | 3 |
|
Cash dividends paid to parent | $ | 68 |
| | $ | 63 |
| | $ | 12 |
|
Contribution from parent | $ | — |
| | $ | 139 |
| | $ | 95 |
|
|
| | | | | | | |
| December 31, |
| 2017 | | 2016 |
Payables to affiliates (current): | | | |
Generation (a) | $ | 6 |
| | $ | 9 |
|
BSC (b) | 5 |
| | 2 |
|
DPL | — |
| | 2 |
|
PHISCO (b) | 18 |
| | 16 |
|
Total payables to affiliates (current) | $ | 29 |
|
| $ | 29 |
|
__________
| |
(a) | ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. See Note 3—Regulatory Matters for additional information. |
| |
(b) | ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
27.Pepco
The financial statements of Pepco include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | |
Generation (a) | $ | 1 |
| | $ | — |
| | $ | 1 |
|
BSC | 1 |
| | — |
| | — |
|
PHISCO | 4 |
| | 6 |
| | 4 |
|
Total operating revenues from affiliates | $ | 6 |
| | $ | 6 |
| | $ | 5 |
|
Purchased power from affiliates | | | | | |
Generation (b) | $ | 206 |
| | $ | 255 |
| | $ | 295 |
|
Operating and maintenance: | | | | | |
PHISCO (c), (e) | $ | — |
| | $ | 219 |
| | $ | 263 |
|
PES (d) | — |
| | 29 |
| | 39 |
|
Total operating and maintenance | $ | — |
| | $ | 248 |
| | $ | 302 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (c) | $ | 89 |
| | $ | 53 |
| | $ | 31 |
|
PHISCO (c), (e) | 137 |
| | 5 |
| | 4 |
|
Total operating and maintenance from affiliates | $ | 226 |
| | $ | 58 |
| | $ | 35 |
|
Capitalized costs: | | | | | |
BSC (c) | $ | 40 |
| | $ | — |
| | $ | — |
|
PHISCO (c) | 32 |
| | — |
| | — |
|
Total capitalized costs | $ | 72 |
| | $ | — |
| | $ | — |
|
Cash dividends paid to parent | $ | 169 |
| | $ | 133 |
| | $ | 136 |
|
Contributions from parent | $ | 166 |
| | $ | 161 |
| | $ | 187 |
|
|
| | | | | | | |
| December 31, |
| 2018 | | 2017 |
Receivables from affiliates (current): | | | |
DPL | $ | 1 |
| | $ | — |
|
Payables to affiliates (current): | | | |
Exelon Corporation | $ | 1 |
| | $ | — |
|
Generation (b) | 28 |
| | 36 |
|
BSC (c) | 19 |
| | 11 |
|
PHISCO (c) | 14 |
| | 27 |
|
Total payables to affiliates (current) | $ | 62 |
| | $ | 74 |
|
__________
| |
(a) | Pepco provides energy to Generation for Generation’s own use. |
| |
(b) | Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs. |
| |
(c) | Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(d) | PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(e) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
DPL
The financial statements of DPL include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | |
BSC | $ | 1 |
| | $ | — |
| | $ | — |
|
PHISCO | 4 |
| | 6 |
| | 5 |
|
ComEd | 1 |
| | — |
| | — |
|
ACE | 1 |
| | — |
| | — |
|
Other | 1 |
| | 2 |
| | 2 |
|
Total operating revenues from affiliates | $ | 8 |
| | $ | 8 |
| | $ | 7 |
|
Purchased power from affiliates | | | | | |
Generation (a) | $ | 120 |
| | $ | 179 |
| | $ | 154 |
|
Operating and maintenance: | | | | | |
PHISCO (b), (d) | $ | — |
| | $ | 165 |
| | $ | 194 |
|
PES (c) | — |
| | 9 |
| | 8 |
|
Total operating and maintenance | $ | — |
| | $ | 174 |
| | $ | 202 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 51 |
| | $ | 31 |
| | $ | 18 |
|
PHISCO (b), (d) | 111 |
| | — |
| | — |
|
Other | — |
| | 1 |
| | 1 |
|
Total operating and maintenance from affiliates | $ | 162 |
| | $ | 32 |
| | $ | 19 |
|
Capitalized costs: | | | | | |
BSC (b)
| $ | 28 |
| | $ | — |
| | $ | — |
|
PHISCO (b)
| 25 |
| | — |
| | — |
|
Total capitalized costs | $ | 53 |
| | $ | — |
| | $ | — |
|
Cash dividends paid to parent | $ | 96 |
| | $ | 112 |
| | $ | 54 |
|
Contributions from parent | $ | 150 |
| | $ | — |
| | $ | 152 |
|
|
| | | | | | | |
| December 31, |
| 2018 | | 2017 |
Payables to affiliates (current): | | | |
Exelon Corporate | $ | 1 |
| | $ | — |
|
Generation (a) | 7 |
| | 12 |
|
BSC (b) | 11 |
| | 7 |
|
PHISCO (b) | 12 |
| | 27 |
|
Pepco | 1 |
| | — |
|
ACE | 1 |
| | — |
|
Total payables to affiliates (current) | $ | 33 |
| | $ | 46 |
|
__________
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(a) | DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. |
| |
(b) | DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | PES performed underground transmission construction services, including services that are treated as capital costs, for DPL. |
| |
(d) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
ACE
The financial statements of ACE include related party transactions as presented in the tables below:
|
| | | | | | | | | | | |
| For the Years Ended December 31, |
| 2018 | | 2017 | | 2016 |
Operating revenues from affiliates: | | | | | |
PHISCO | $ | 2 |
| | $ | 1 |
| | $ | 2 |
|
Other | 1 |
| | 1 |
| | 1 |
|
Total operating revenues from affiliates | $ | 3 |
| | $ | 2 |
| | $ | 3 |
|
Purchased power from affiliates | | | | | |
Generation (a) | $ | 29 |
| | $ | 29 |
| | $ | 37 |
|
Operating and maintenance: | | | | | |
PHISCO (b), (c) | $ | — |
| | $ | 135 |
| | $ | 155 |
|
Operating and maintenance from affiliates: | | | | | |
BSC (b) | $ | 42 |
| | $ | 25 |
| | $ | 15 |
|
PHISCO (b), (c) | 98 |
| | — |
| | — |
|
Other | 2 |
| | 3 |
| | 3 |
|
Total operating and maintenance from affiliates | $ | 142 |
| | $ | 28 |
| | $ | 18 |
|
Capitalized costs: | | | | | |
BSC (b)
| $ | 20 |
| | $ | — |
| | $ | — |
|
PHISCO (b)
| 21 |
| | — |
| | — |
|
Total capitalized costs | $ | 41 |
| | $ | — |
| | $ | — |
|
Cash dividends paid to parent | $ | 59 |
| | $ | 68 |
| | $ | 63 |
|
Contributions from parent | $ | 67 |
| | $ | — |
| | $ | 139 |
|
|
| | | | | | | |
| December 31, |
| 2018 | | 2017 |
Receivable from affiliate (current): | | | |
DPL | $ | 1 |
| | $ | — |
|
Payables to affiliates (current): | | | |
Generation (a) | $ | 5 |
| | $ | 6 |
|
BSC (b) | 8 |
| | 5 |
|
PHISCO (b) | 13 |
| | 18 |
|
Other | 2 |
| | — |
|
Total payables to affiliates (current) | $ | 28 |
|
| $ | 29 |
|
__________
| |
(a) | ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
| |
(b) | ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized. |
| |
(c) | Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018. |
26. Quarterly Data (Unaudited) (All Registrants)
Exelon
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:
| | | Operating Revenues | | Operating Income | | Net Income Attributable to Common Shareholders | Operating Revenues | | Operating Income | | Net Income Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | | | | | | | | | | | | |
March 31 | $ | 8,757 |
| | $ | 7,573 |
| | $ | 1,296 |
| | $ | 483 |
| | $ | 995 |
| | $ | 173 |
| $ | 9,693 |
| | $ | 8,747 |
| | $ | 1,101 |
| | $ | 1,308 |
| | $ | 585 |
| | $ | 990 |
|
June 30 | 7,623 |
| | 6,910 |
| | 232 |
| | 647 |
| | 80 |
| | 267 |
| 8,076 |
| | 7,665 |
| | 942 |
| | 300 |
| | 539 |
| | 95 |
|
September 30 | 8,769 |
| | 9,002 |
| | 1,475 |
| | 1,267 |
| | 824 |
| | 490 |
| 9,403 |
| | 8,768 |
| | 1,146 |
| | 1,499 |
| | 733 |
| | 823 |
|
December 31 | 8,381 |
| | 7,875 |
| | 1,258 |
| | 714 |
| | 1,871 |
| | 204 |
| 8,814 |
| | 8,384 |
| | 708 |
| | 1,288 |
| | 152 |
| | 1,880 |
|
|
| | | | | | | | | | | | | |
| Average Basic Shares Outstanding (in millions) | | Net Income per Basic Share |
| 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | |
March 31 | 928 |
| | 923 |
| | $ | 1.07 |
| | $ | 0.19 |
|
June 30 | 934 |
| | 924 |
| | 0.09 |
| | 0.29 |
|
September 30 | 962 |
| | 925 |
| | 0.86 |
| | 0.53 |
|
December 31 | 964 |
| | 925 |
| | 1.94 |
| | 0.22 |
|
| Average Diluted Shares Outstanding (in millions) | | Net Income per Diluted Share |
| 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | |
March 31 | 930 |
| | 925 |
| | $ | 1.07 |
| | $ | 0.19 |
|
June 30 | 936 |
| | 926 |
| | 0.09 |
| | 0.29 |
|
September 30 | 965 |
| | 927 |
| | 0.85 |
| | 0.53 |
|
December 31 | 967 |
| | 928 |
| | 1.93 |
| | 0.22 |
|
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2017 | | 2016 |
| Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter | | Fourth Quarter | | Third Quarter | | Second Quarter | | First Quarter |
High price | $ | 42.67 |
| | $ | 38.78 |
| | $ | 37.44 |
| | $ | 37.19 |
| | $ | 36.36 |
| | $ | 37.70 |
| | $ | 36.37 |
| | $ | 35.95 |
|
Low price | 37.55 |
| | 35.37 |
| | 33.30 |
| | 34.47 |
| | 29.82 |
| | 32.86 |
| | 33.18 |
| | 26.26 |
|
Close | 39.41 |
| | 37.67 |
| | 36.07 |
| | 35.98 |
| | 35.49 |
| | 33.29 |
| | 36.36 |
| | 35.86 |
|
Dividends | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.328 |
| | 0.318 |
| | 0.318 |
| | 0.318 |
| | 0.310 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
|
| | | | | | | | | | | | | | | |
| Net Income per Basic Share | | Net Income per Diluted Share |
| 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | |
March 31 | $ | 0.61 |
| | $ | 1.07 |
| | $ | 0.60 |
| | $ | 1.06 |
|
June 30 | 0.56 |
| | 0.10 |
| | 0.56 |
| | 0.10 |
|
September 30 | 0.76 |
| | 0.86 |
| | 0.76 |
| | 0.85 |
|
December 31 | 0.16 |
| | 1.95 |
| | 0.16 |
| | 1.94 |
|
Generation
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating (Loss) Income | | Net (Loss) Income Attributable to Membership Interest |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 4,888 |
| | $ | 4,739 |
| | $ | 387 |
| | $ | 415 |
| | $ | 423 |
| | $ | 310 |
|
June 30 | 4,174 |
| | 3,589 |
| | (467 | ) | | (13 | ) | | (250 | ) | | (8 | ) |
September 30 | 4,751 |
| | 5,035 |
| | 500 |
| | 342 |
| | 305 |
| | 236 |
|
December 31 | 4,654 |
| | 4,388 |
| | 501 |
| | 94 |
| | 2,215 |
| | (41 | ) |
ComEd
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 1,298 |
| | $ | 1,249 |
| | $ | 314 |
| | $ | 274 |
| | $ | 141 |
| | $ | 115 |
|
June 30 | 1,357 |
| | 1,286 |
| | 319 |
| | 324 |
| | 118 |
| | 145 |
|
September 30 | 1,571 |
| | 1,497 |
| | 404 |
| | 389 |
| | 189 |
| | 37 |
|
December 31 | 1,309 |
| | 1,223 |
| | 286 |
| | 217 |
| | 120 |
| | 80 |
|
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 796 |
| | $ | 841 |
| | $ | 192 |
| | $ | 196 |
| | $ | 127 |
| | $ | 124 |
|
June 30 | 630 |
| | 664 |
| | 137 |
| | 152 |
| | 88 |
| | 100 |
|
September 30 | 715 |
| | 788 |
| | 169 |
| | 204 |
| | 112 |
| | 122 |
|
December 31 | 729 |
| | 701 |
| | 157 |
| | 150 |
| | 107 |
| | 92 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 951 |
| | $ | 929 |
| | $ | 228 |
| | $ | 187 |
| | $ | 125 |
| | $ | 98 |
|
June 30 | 674 |
| | 680 |
| | 98 |
| | 59 |
| | 45 |
| | 31 |
|
September 30 | 738 |
| | 812 |
| | 124 |
| | 115 |
| | 62 |
| | 54 |
|
December 31 | 813 |
| | 812 |
| | 163 |
| | 190 |
| | 76 |
| | 103 |
|
PHI
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Successor | |
| Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Attributable to Membership Interest | |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | |
Quarter ended: | | | | | | | | | | | | |
March 31 | $ | 1,175 |
| | $ | 105 |
| (a) | $ | 180 |
| | $ | (411 | ) | (a) | $ | 140 |
| | $ | (309 | ) | (a) |
June 30 | 1,074 |
| | 1,066 |
| | 148 |
| | 136 |
| | 66 |
| | 52 |
| |
September 30 | 1,310 |
| | 1,394 |
| | 285 |
| | 279 |
| | 153 |
| | 166 |
| |
December 31 | 1,121 |
| | 1,078 |
| | 159 |
| | 90 |
| | 4 |
| | 30 |
| |
|
| | | | | | | | |
| Predecessor |
| Operating Revenues | | Operating Income | | Net Income Attributable to Membership Interest |
| | | | | |
January 1, 2016 - March 23, 2016 | 1,153 |
| | 105 |
| | 19 |
|
__________
| |
(a) | Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016. |
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 530 |
| | $ | 551 |
| | $ | 79 |
| | $ | (105 | ) | | $ | 58 |
| | $ | (108 | ) |
June 30 | 514 |
| | 509 |
| | 84 |
| | 97 |
| | 43 |
| | 49 |
|
September 30 | 604 |
| | 635 |
| | 149 |
| | 132 |
| | 87 |
| | 79 |
|
December 31 | 510 |
| | 491 |
| | 87 |
| | 51 |
| | 17 |
| | 23 |
|
DPL
The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 362 |
| | $ | 362 |
| | $ | 78 |
| | $ | (72 | ) | | $ | 57 |
| | $ | (72 | ) |
June 30 | 282 |
| | 281 |
| | 41 |
| | 30 |
| | 19 |
| | 12 |
|
September 30 | 327 |
| | 331 |
| | 59 |
| | 72 |
| | 31 |
| | 44 |
|
December 31 | 330 |
| | 303 |
| | 52 |
| | 20 |
| | 14 |
| | 7 |
|
ACE
The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Attributable to Common Shareholders |
| 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 275 |
| | $ | 291 |
| | $ | 25 |
| | $ | (121 | ) | | $ | 28 |
| | $ | (100 | ) |
June 30 | 270 |
| | 270 |
| | 25 |
| | 19 |
| | 8 |
| | 3 |
|
September 30 | 370 |
| | 421 |
| | 79 |
| | 83 |
| | 41 |
| | 47 |
|
December 31 | 271 |
| | 275 |
| | 28 |
| | 26 |
| | — |
| | 8 |
|
28. Subsequent Events (Exelon, Generation and ComEd)
Illinois ZEC Procurement
On January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event. Generation executed the ZEC procurement contracts with Illinois utilities, including |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income (Loss) | | Net Income (Loss) Attributable to Membership Interest |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 5,512 |
| | $ | 4,878 |
| | $ | 347 |
| | $ | 373 |
| | $ | 136 |
| | $ | 418 |
|
June 30 | 4,579 |
| | 4,216 |
| | 282 |
| | (427 | ) | | 178 |
| | (235 | ) |
September 30 | 5,278 |
| | 4,750 |
| | 311 |
| | 497 |
| | 234 |
| | 304 |
|
December 31 | 5,069 |
| | 4,657 |
| | 35 |
| | 504 |
| | (178 | ) | | 2,224 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd effective
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 1,512 |
| | $ | 1,298 |
| | $ | 292 |
| | $ | 314 |
| | $ | 165 |
| | $ | 141 |
|
June 30 | 1,398 |
| | 1,357 |
| | 288 |
| | 319 |
| | 164 |
| | 118 |
|
September 30 | 1,598 |
| | 1,571 |
| | 323 |
| | 404 |
| | 193 |
| | 189 |
|
December 31 | 1,373 |
| | 1,309 |
| | 242 |
| | 286 |
| | 141 |
| | 120 |
|
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 866 |
| | $ | 796 |
| | $ | 142 |
| | $ | 192 |
| | $ | 113 |
| | $ | 127 |
|
June 30 | 653 |
| | 630 |
| | 127 |
| | 137 |
| | 96 |
| | 88 |
|
September 30 | 757 |
| | 715 |
| | 154 |
| | 169 |
| | 126 |
| | 112 |
|
December 31 | 765 |
| | 729 |
| | 165 |
| | 157 |
| | 124 |
| | 107 |
|
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 977 |
| | $ | 951 |
| | $ | 177 |
| | $ | 228 |
| | $ | 128 |
| | $ | 125 |
|
June 30 | 662 |
| | 674 |
| | 85 |
| | 98 |
| | 51 |
| | 45 |
|
September 30 | 731 |
| | 738 |
| | 103 |
| | 124 |
| | 63 |
| | 62 |
|
December 31 | 799 |
| | 813 |
| | 109 |
| | 163 |
| | 71 |
| | 76 |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income Attributable to Membership Interest |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 1,251 |
| | $ | 1,175 |
| | $ | 126 |
| | $ | 180 |
| | $ | 65 |
| | $ | 140 |
|
June 30 | 1,076 |
| | 1,074 |
| | 153 |
| | 148 |
| | 84 |
| | 66 |
|
September 30 | 1,361 |
| | 1,310 |
| | 245 |
| | 285 |
| | 187 |
| | 153 |
|
December 31 | 1,117 |
| | 1,121 |
| | 126 |
| | 159 |
| | 62 |
| | 4 |
|
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 557 |
| | $ | 530 |
| | $ | 56 |
| | $ | 79 |
| | $ | 31 |
| | $ | 58 |
|
June 30 | 523 |
| | 514 |
| | 85 |
| | 84 |
| | 54 |
| | 43 |
|
September 30 | 628 |
| | 604 |
| | 112 |
| | 149 |
| | 89 |
| | 87 |
|
December 31 | 531 |
| | 510 |
| | 65 |
| | 87 |
| | 36 |
| | 17 |
|
DPL
The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 384 |
| | $ | 362 |
| | $ | 49 |
| | $ | 78 |
| | $ | 31 |
| | $ | 57 |
|
June 30 | 289 |
| | 282 |
| | 42 |
| | 41 |
| | 26 |
| | 19 |
|
September 30 | 328 |
| | 327 |
| | 51 |
| | 59 |
| | 33 |
| | 31 |
|
December 31 | 331 |
| | 330 |
| | 48 |
| | 52 |
| | 30 |
| | 14 |
|
ACE
The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | Operating Income | | Net Income (Loss) |
| 2018 | | 2017 | | 2018 | | 2017 | | 2018 | | 2017 |
Quarter ended: | | | | | | | | | | | |
March 31 | $ | 310 |
| | $ | 275 |
| | $ | 23 |
| | $ | 25 |
| | $ | 7 |
| | $ | 28 |
|
June 30 | 265 |
| | 270 |
| | 25 |
| | 25 |
| | 8 |
| | 8 |
|
September 30 | 406 |
| | 370 |
| | 84 |
| | 79 |
| | 61 |
| | 41 |
|
December 31 | 254 |
| | 271 |
| | 14 |
| | 28 |
| | (1 | ) | | — |
|
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
27. Subsequent Events (Exelon and Generation)
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to Pacific Gas and Electric Company (PG&E) through a PPA. As of December 31, 2018, Generation had approximately $750 million and $510 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. The nonrecourse debt is guaranteed by the DOE Loan Programs Office. Neither the guarantor nor the lender have recourse against Exelon or Generation in the event of default.
On January 26,29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PG&E’s bankruptcy creates an event of default for Antelope Valley’s nonrecourse debt. As such, Antelope Valley is currently in discussions with the DOE Loan Programs Office, and the debt has not yet been accelerated. Given that the event of default did not occur until January 2019, the debt continued to be classified as non-current on Exelon’s and Generation’s Consolidated Balance Sheets as of December 31, 2018, and will begin recognizing revenue. Winning bidders willmay be entitledreclassified to compensation for the salecurrent in 2019.
Generation has also assessed and determined that Antelope Valley’s long-lived assets are not impaired as of ZECs retroactive to the June 1, 2017 effective date of FEJA. In the first quarter of 2018, Generation will recognize approximately $150 million of revenue and ComEd will record an obligation to Generation and corresponding reduction to its regulatory liability of approximately $100 million related to ZECs generated from June 1, 2017 through December 31, 2017.
Early Retirement2018. Changes in assumptions such as the likelihood of Oyster Creek Generating Station
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle in October 2018. In 2010, Generation announced that Oyster Creek would retire by the end of 2019PPA being rejected as part of an agreement with the Statebankruptcy proceedings could potentially result in future impairments of New Jersey to avoid significant costs associated withAntelope Valley. The impairment loss could be substantially all of the construction of cooling towers to meetnet long-lived assets if Antelope Valley was valued without the State’s then new environmental regulations. Since then, like other nuclear sites, Oyster Creek has continued to face rising operating costs amid a historically low wholesale power price environment. The decision to retire Oyster CreekPPA. Generation is monitoring the bankruptcy proceedings for any changes in 2018 at the end of its current operating cycle involved consideration of several factors, including economic and operating efficiencies, and avoids a refueling outage scheduled for the fall of 2018circumstances that would have required advanced purchasing of fuel fabrication and materials beginning in late February 2018.
Becauseindicate the carrying amount of the decision to retire Oyster Creek in 2018,net long-lived assets of Antelope Valley may not be recoverable.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,990 million and $830 million of additional net long-lived assets and nonrecourse debt outstanding, respectively, as of December 31, 2018. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation will recognize certain one-time chargesand includes Generation's interest in EGRP and other projects with non-controlling interests. EGR IV is currently not in default, however, an acceleration of Antelope Valley’s debt could impact EGR IV. The lenders do not have recourse against Exelon or Generation in the first quarterevent of 2018 ranging from an estimated $25 million to $35 million (pre-tax) related to a materialsdefault by EGR IV. See Note 2 - Variable Interest Entities for additional details on EGRP and supplies inventory reserve adjustment, employee-related costs,Note 13 — Debt and construction work-in-progress impairment, among other items. Estimated cash expenditures related to the one-time charges primarilyCredit Agreements for employee-related costs are expected to range from $5 million to $10 million.
In addition to these one-time charges, there will be financial impacts stemming from shortening the expected economic useful life of Oyster Creek primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. The following table summarizes the estimated amount of expected incremental non-cash expense items expected to be incurred in 2018 because of the early retirement decision.details on Generation's nonrecourse project financings.
|
| | |
| | Projected(b)
|
Income statement expense (pre-tax) | | 2018 |
Depreciation and Amortization | | |
Accelerated depreciation(a)
| | $110 to $140 |
Accelerated nuclear fuel amortization | | $40 |
Operating and Maintenance | | |
Increased ARO accretion | | Up to $5 |
__________
| |
(a) | Includes the accelerated depreciation of plant assets including any ARC. |
| |
(b) | Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. |
|
| |
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
All Registrants
None.
|
| |
ITEM 9A. | CONTROLS AND PROCEDURES |
All Registrants—Disclosure Controls and Procedures
During the fourth quarter of 2017,2018, each registrant’s management, including its principal executive officer and principal financial officer, evaluated the effectiveness of that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure controls and procedures have been designed by each registrant to ensure that (a) information relating to that registrant, including its consolidated subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that registrant’s management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2017,2018, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s disclosure controls and procedures were effective to accomplish their objectives.
All Registrants—Changes in Internal Control Over Financial Reporting
Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth quarter of 20172018 that have materially affected, or are reasonably likely to materially affect, any of the registrant's internal control over financial reporting.
All Registrants—Internal Control Over Financial Reporting
Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2017.2018. As a result of that assessment, management determined that there were no material weaknesses as of December 31, 20172018 and, therefore, concluded that each registrant’s internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
|
| |
ITEM 9B. | OTHER INFORMATION |
All Registrants
None.
PART III
Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL and ACE are not presented.
|
| |
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
Executive Officers
The information required by ITEM 1010. relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive Officersofficers of the Registrants at February 9, 2018.
8, 2019.
Directors, Director Nomination Process and Audit Committee
The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)) and the beneficial reporting compliance (Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon’s definitive 20182019 proxy statement (2018(2019 Exelon Proxy Statement) and the ComEd information statement (2018(2019 ComEd Information Statement) to be filed with the SEC on or before April 29, 201830, 2019 pursuant to Regulation 14A or 14C, as applicable, under the Securities Exchange Act of 1934.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s and ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website at www.exeloncorp.com.www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document from Carter C. Culver, Senior Vice President and Deputy General Counsel, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com,, or in a report on Form 8-K.
|
| |
ITEM 11. | EXECUTIVE COMPENSATION |
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy Statement for the 20182019 Annual Meeting of Shareholders or the ComEd 20182019 Information Statement, which are incorporated herein by reference.
|
| |
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2019 Exelon Proxy Statement for the 2018 Annual Meeting of Shareholders or the ComEd 20182019 Information Statement which areand incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
| | [A] | [B] | | [C] | | [D] | |
| | [A] | | [B] | | [C] |
Plan Category | Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) | | Weighted-average price of outstanding Options, warrants and rights (Note 2) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [B]) (Note 3) | Number of securities to be issued upon exercise of outstanding Options, warrants and rights (Note 1) | | Weighted-average price of outstanding Options, warrants and rights (Note 2) | | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column [B]) (Note 3) |
Equity compensation plans approved by security holders | 21,755,400 |
| | $ | 28.13 |
| | 23,634,900 |
| 10,401,300 |
| | $ | 23.77 |
| | 30,071,500 |
|
__________
| |
(1) | Balance includes stock options, unvested performance shares, and unvested restricted shares granted under the Exelon LTIP or predecessor company plans including shares awarded under those plans and deferred into the stock deferral plan, and deferred stock units granted to directors as part of their compensation. Unvested performance shares are subject to performance metrics ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance shares granted in 2015, 2016, 2017 and 2017,2018, the total includes the number of shares that could be granted,issued pursuant to the terms of the Exelon LTIP plan, which provides that final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing a best case performance scenario, for a total of 9,546,0004,942,100 shares. If the performance and total shareholder return modifier metrics were at target, the number of securities to be issued for such awards would be 4,773,000.2,471,000. The deferred stock units granted to directors includes 384,900433,400 shares to be issued upon the conversion of deferred stock units awarded to members of the Exelon Board of Directors, and 109,200 shares to be issued upon the conversion of stock units held by members of the Exelon Board of Directors that were earned under a legacy Constellation Energy Group plan.Directors. Conversion of the deferred stock units to shares will occuroccurs after thea director terminates service to the Exelon board or the board of any of its subsidiary companies. See Note 20—19 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for additional information about the material features of the plans. |
| |
(2) | Includes outstanding restricted stock units andThe weighted-average price reported in column B does not take the performance shares that can be exercised for no consideration. Without such instruments, the weighted-average price of outstanding options, warrants and rights shown in column [C] would be $47.69.shares credited to deferred compensation plans into account. |
| |
(3) | Includes 19,737,60018,410,700 shares remaining available for issuance from the company’s employee stock purchase plan. |
No ComEd securities are authorized for issuance under equity compensation plans.
|
| |
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE |
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy Statement for the 20182019 Annual Meeting of Shareholders or the ComEd 20182019 Information Statement, which are incorporated herein by reference.
|
| |
ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 20182019 in the Exelon Proxy Statement for the 20182019 Annual Meeting of Shareholders and the ComEd 20182019 Information Statement, which are incorporated herein by reference.
PART IV
|
| |
ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
| |
(a) | The following documents are filed as a part of this report: |
(1) Exelon
|
| | |
1.(i) | | Financial Statements:Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| | |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| | |
| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
| | |
| | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| | |
| | Notes to Consolidated Financial Statements |
| | |
2.(ii) | | Financial Statement Schedules: |
| | |
| | Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 20172018 and 20162017 and for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| | |
| | Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
| | |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto. |
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating expenses | | | | | | | | | | |
Operating and maintenance | $ | 10 |
| | $ | 221 |
| | $ | — |
| $ | (5 | ) | | $ | 10 |
| | $ | 221 |
|
Operating and maintenance from affiliates | 25 |
| | 51 |
| | 43 |
| 9 |
| | 25 |
| | 51 |
|
Other | 4 |
| | 4 |
| | 4 |
| 4 |
| | 4 |
| | 4 |
|
Total operating expenses | 39 |
| | 276 |
| | 47 |
| 8 |
| | 39 |
| | 276 |
|
Operating loss | (39 | ) | | (276 | ) | | (47 | ) | (8 | ) | | (39 | ) | | (276 | ) |
Other income and (deductions) | | | | | | | | | | |
Interest expense, net | (315 | ) | | (312 | ) | | (168 | ) | (312 | ) | | (315 | ) | | (312 | ) |
Equity in earnings of investments | 4,398 |
| | 1,521 |
| | 2,461 |
| 2,188 |
| | 4,414 |
| | 1,508 |
|
Interest income from affiliates, net | 40 |
| | 39 |
| | 43 |
| 42 |
| | 40 |
| | 39 |
|
Other, net | 1 |
| | 7 |
| | (43 | ) | 3 |
| | 1 |
| | 7 |
|
Total other income | 4,124 |
| | 1,255 |
| | 2,293 |
| 1,921 |
| | 4,140 |
| | 1,242 |
|
Income before income taxes | 4,085 |
| | 979 |
| | 2,246 |
| 1,913 |
| | 4,101 |
| | 966 |
|
Income taxes | 315 |
| | (155 | ) | | (23 | ) | (97 | ) | | 315 |
| | (155 | ) |
Net income | $ | 3,770 |
| | $ | 1,134 |
| | $ | 2,269 |
| $ | 2,010 |
| | $ | 3,786 |
| | $ | 1,121 |
|
Other comprehensive income (loss) | | | | | | | | | | |
Pension and non-pension postretirement benefit plans: | | | | | | | | | | |
Prior service benefit reclassified to periodic costs | $ | (56 | ) | | $ | (48 | ) | | $ | (46 | ) | $ | (66 | ) | | $ | (56 | ) | | $ | (48 | ) |
Actuarial loss reclassified to periodic cost | 197 |
| | 184 |
| | 220 |
| 247 |
| | 197 |
| | 184 |
|
Pension and non-pension postretirement benefit plan valuation adjustment | 10 |
| | (181 | ) | | (99 | ) | (143 | ) | | 10 |
| | (181 | ) |
Unrealized gain on cash flow hedges | 3 |
| | 2 |
| | 9 |
| 12 |
| | 3 |
| | 2 |
|
Unrealized gain on marketable securities | 6 |
| | 1 |
| | — |
| — |
| | 6 |
| | 1 |
|
Unrealized gain (loss) on equity investments | 6 |
| | (4 | ) | | (3 | ) | 1 |
| | 6 |
| | (4 | ) |
Unrealized gain (loss) on foreign currency translation | 7 |
| | 10 |
| | (21 | ) | |
Unrealized (loss) gain on foreign currency translation | | (10 | ) | | 7 |
| | 10 |
|
Other comprehensive income (loss) | 173 |
|
| (36 | ) |
| 60 |
| 41 |
|
| 173 |
|
| (36 | ) |
Comprehensive income | $ | 3,943 |
| | $ | 1,098 |
| | $ | 2,329 |
| $ | 2,051 |
| | $ | 3,959 |
| | $ | 1,085 |
|
See the Notes to Financial Statements
586486
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Net cash flows provided by operating activities | $ | 1,921 |
| | $ | 1,029 |
| | $ | 3,071 |
| $ | 2,581 |
| | $ | 1,921 |
| | $ | 1,029 |
|
Cash flows from investing activities | | | | | | | | | | |
Changes in Exelon intercompany money pool | (129 | ) | | 1,390 |
| | (1,217 | ) | 1 |
| | (129 | ) | | 1,390 |
|
Notes receivable from affiliates | — |
| | — |
| | 550 |
| |
Investment in affiliates | (1,717 | ) | | (1,757 | ) | | (212 | ) | (1,236 | ) | | (1,717 | ) | | (1,757 | ) |
Acquisition of business | — |
| | (6,962 | ) | | — |
| — |
| | — |
| | (6,962 | ) |
Other investing activities | (5 | ) | | 5 |
| | (55 | ) | — |
| | (5 | ) | | 5 |
|
Net cash flows used in investing activities | (1,851 | ) |
| (7,324 | ) |
| (934 | ) | (1,235 | ) |
| (1,851 | ) |
| (7,324 | ) |
Cash flows from financing activities | | | | | | | | | | |
Issuance of long-term debt | — |
| | 1,800 |
| | 4,200 |
| — |
| | — |
| | 1,800 |
|
Proceeds from short-term borrowings with maturities greater than 90 days | 500 |
| | — |
| | — |
| — |
| | 500 |
| | — |
|
Retirement of long-term debt | (569 | ) | | (46 | ) | | (2,263 | ) | — |
| | (569 | ) | | (46 | ) |
Issuance of common stock | — |
| | — |
| | 1,868 |
| |
Common stock issued from treasury stock | 1,150 |
| | — |
| | — |
| — |
| | 1,150 |
| | — |
|
Dividends paid on common stock | (1,236 | ) | | (1,166 | ) | | (1,105 | ) | (1,332 | ) | | (1,236 | ) | | (1,166 | ) |
Proceeds from employee stock plans | 150 |
| | 55 |
| | 32 |
| 105 |
| | 150 |
| | 55 |
|
Other financing activities | (9 | ) | | (20 | ) | | (58 | ) | (4 | ) | | (9 | ) | | (20 | ) |
Net cash flows (used in) provided by financing activities | (14 | ) | | 623 |
| | 2,674 |
| (1,231 | ) | | (14 | ) | | 623 |
|
Increase (Decrease) in cash and cash equivalents | 56 |
| | (5,672 | ) | | 4,811 |
| |
Cash and cash equivalents at beginning of period | 18 |
| | 5,690 |
| | 879 |
| |
Cash and cash equivalents at end of period | $ | 74 |
| | $ | 18 |
| | $ | 5,690 |
| |
Increase (Decrease) in cash, cash equivalents and restricted cash | | 115 |
| | 56 |
| | (5,672 | ) |
Cash, cash equivalents and restricted cash at beginning of period | | 74 |
| | 18 |
| | 5,690 |
|
Cash, cash equivalents and restricted cash at end of period | | $ | 189 |
| | $ | 74 |
| | $ | 18 |
|
See the Notes to Financial Statements
587487
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
ASSETS | | | | | | |
Current assets | | | | | | |
Cash and cash equivalents | $ | 74 |
| | $ | 18 |
| $ | 189 |
| | $ | 74 |
|
Deposit with IRS | — |
| | 1,250 |
| |
Accounts receivable, net | | | | | | |
Other accounts receivable | 431 |
| | 73 |
| 48 |
| | 431 |
|
Accounts receivable from affiliates | 33 |
| | 48 |
| 44 |
| | 33 |
|
Notes receivable from affiliates | 217 |
| | 88 |
| 216 |
| | 217 |
|
Regulatory assets | 284 |
| | 263 |
| 182 |
| | 284 |
|
Other | 4 |
| | — |
| 4 |
| | 4 |
|
Total current assets | 1,043 |
| | 1,740 |
| 683 |
| | 1,043 |
|
Property, plant and equipment, net | 50 |
| | 51 |
| 48 |
| | 50 |
|
Deferred debits and other assets | | | | | | |
Regulatory assets | 3,697 |
| | 4,033 |
| 3,742 |
| | 3,697 |
|
Investments in affiliates | 39,272 |
| | 34,869 |
| 40,448 |
| | 39,311 |
|
Deferred income taxes | 1,431 |
| | 2,107 |
| 1,455 |
| | 1,431 |
|
Notes receivable from affiliates | 910 |
| | 922 |
| 898 |
| | 910 |
|
Other | 234 |
| | 256 |
| 235 |
| | 234 |
|
Total deferred debits and other assets | 45,544 |
| | 42,187 |
| 46,778 |
| | 45,583 |
|
Total assets | $ | 46,637 |
| | $ | 43,978 |
| $ | 47,509 |
| | $ | 46,676 |
|
See the Notes to Financial Statements
588488
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
| | | December 31, | December 31, |
(In millions) | 2017 | | 2016 | 2018 | | 2017 |
LIABILITIES AND SHAREHOLDERS’ EQUITY | | | | | | |
Current liabilities | | | | | | |
Short-term borrowings | $ | 500 |
| | $ | — |
| $ | 500 |
| | $ | 500 |
|
Long-term debt due within one year | — |
| | 570 |
| |
Accounts payable | 2 |
| | 2 |
| 1 |
| | 2 |
|
Accrued expenses | 99 |
| | 489 |
| 184 |
| | 99 |
|
Payables to affiliates | 360 |
| | 706 |
| 360 |
| | 360 |
|
Regulatory liabilities | 16 |
| | 16 |
| 15 |
| | 16 |
|
Pension obligations | 65 |
| | 58 |
| 63 |
| | 65 |
|
Other | 46 |
| | 50 |
| 14 |
| | 46 |
|
Total current liabilities | 1,088 |
| | 1,891 |
| 1,137 |
| | 1,088 |
|
Long-term debt | 7,161 |
| | 7,193 |
| 7,147 |
| | 7,161 |
|
Deferred credits and other liabilities | | | | | | |
Regulatory liabilities | 15 |
| | 31 |
| 32 |
| | 15 |
|
Pension obligations | 7,792 |
| | 8,608 |
| 7,795 |
| | 7,792 |
|
Non-pension postretirement benefit obligations | 322 |
| | 7 |
| 199 |
| | 322 |
|
Deferred income taxes | 220 |
| | 226 |
| 233 |
| | 220 |
|
Other | 180 |
| | 182 |
| 202 |
| | 180 |
|
Total deferred credits and other liabilities | 8,529 |
| | 9,054 |
| 8,461 |
| | 8,529 |
|
Total liabilities | 16,778 |
| | 18,138 |
| 16,745 |
| | 16,778 |
|
Commitments and contingencies |
| |
|
| |
|
Shareholders’ equity | | | | | | |
Common stock (No par value, 2000 shares authorized, 963 shares and 924 shares outstanding at December 31, 2017 and 2016, respectively) | 18,966 |
| | 18,797 |
| |
Treasury stock, at cost (2 shares and 35 shares at December 31, 2017 and 2016, respectively) | (123 | ) | | (2,327 | ) | |
Common stock (No par value, 2,000 shares authorized, 968 shares and 963 shares outstanding at December 31, 2018 and 2017, respectively) | | 19,116 |
| | 18,966 |
|
Treasury stock, at cost (2 shares at December 31, 2018 and 2017) | | (123 | ) | | (123 | ) |
Retained earnings | 13,503 |
| | 12,030 |
| 14,766 |
| | 14,081 |
|
Accumulated other comprehensive loss, net | (2,487 | ) | | (2,660 | ) | (2,995 | ) | | (3,026 | ) |
Total shareholders’ equity | 29,859 |
| | 25,840 |
| 30,764 |
| | 29,898 |
|
Total liabilities and shareholders’ equity | $ | 46,637 |
| | $ | 43,978 |
| $ | 47,509 |
| | $ | 46,676 |
|
See the Notes to Financial Statements
589489
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
1. Basis of Presentation
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. BGE redeemed all of its outstanding preferred stock in 2016.
2. Mergers
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). See Note 4—5—Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI Merger.
3. Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 20172018 and December 31, 2016.2017.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement which expiresexpired on March 22, 2018. The loan agreement was renewed on March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.
Credit Agreements
On May 26, 2016, Exelon Corporate amended and extended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2017,2018, Exelon Corporation had available capacity under those commitments of $555$591 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for furtheradditional information regarding Exelon Corporation’s credit agreement.
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
Long-Term Debt
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 20172018 and December 31, 2016:2017:
| | | | | | | Maturity Date | | December 31, | | | | | Maturity Date | | December 31, |
| Rates | | 2017 | | 2016 | Rates | | 2018 | | 2017 |
Long-term debt | | | | | | | | | | | | | | |
Junior subordinated notes | | | 3.50 | % | | 2022 | | $ | 1,150 |
| | $ | 1,150 |
| | | 3.50 | % | | 2022 | | $ | 1,150 |
| | $ | 1,150 |
|
Contract payment - junior subordinated notes | | | 2.50 | % | | 2017 | | — |
| | 19 |
| |
Senior unsecured notes(a) | 2.45 | % | | 7.60 | % | | 2020 - 2046 | | 5,889 |
| | 6,439 |
| 2.45 | % | | 7.60 | % | | 2020 - 2046 | | 5,889 |
| | 5,889 |
|
Total long-term debt | | | | | 7,039 |
| | 7,608 |
| | | | | 7,039 |
| | 7,039 |
|
Unamortized debt discount and premium, net | | | | | (8 | ) | | (8 | ) | | | | | (7 | ) | | (8 | ) |
Unamortized debt issuance costs | | | | | (49 | ) | | (57 | ) | | | | | (47 | ) | | (49 | ) |
Fair value adjustment of consolidated subsidiary | | | | | 179 |
| | 220 |
| | | | | 162 |
| | 179 |
|
Long-term debt due within one year | | | | | — |
| | (570 | ) | |
Long-term debt | | | | | $ | 7,161 |
|
| $ | 7,193 |
| | | | | $ | 7,147 |
|
| $ | 7,161 |
|
__________
| |
(a) | Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets. |
The debt maturities for Exelon Corporate for the periods 2018,2019, 2020, 2021, 2022, 2023 and thereafter are as follows:
| | 2018 | $ | — |
| |
2019 | — |
| $ | — |
|
2020 | 1,450 |
| 1,450 |
|
2021 | 300 |
| 300 |
|
2022 | 1,150 |
| 1,150 |
|
2023 | | — |
|
Remaining years | 4,139 |
| 4,139 |
|
Total long-term debt | $ | 7,039 |
| $ | 7,039 |
|
4. Commitments and Contingencies
See Note 23—22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
5. Related Party Transactions
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
| | | For the Years Ended December 31, | For the Years Ended December 31, |
(In millions) | 2017 | | 2016 | | 2015 | 2018 | | 2017 | | 2016 |
Operating and maintenance from affiliates: | | | | | | | | | | |
BSC (a) | $ | 23 |
| | $ | 51 |
| | $ | 43 |
| $ | 11 |
| | $ | 23 |
| | $ | 51 |
|
Other | 2 |
| | — |
| | — |
| (2 | ) | | 2 |
| | — |
|
Total operating and maintenance from affiliates: | $ | 25 |
| | $ | 51 |
| | $ | 43 |
| $ | 9 |
| | $ | 25 |
| | $ | 51 |
|
Interest income from affiliates, net: | | | | | | | | | | |
Generation | $ | 37 |
| | $ | 39 |
| | $ | 43 |
| $ | 36 |
| | $ | 37 |
| | $ | 39 |
|
BSC | 3 |
| | — |
| | — |
| 4 |
| | 3 |
| | — |
|
Exelon Energy Delivery Company, LLC(b) | | $ | 2 |
| | $ | — |
| | $ | — |
|
Total interest income from affiliates, net: | $ | 40 |
| | $ | 39 |
| | $ | 43 |
| $ | 42 |
| | $ | 40 |
| | $ | 39 |
|
Equity in earnings (losses) of investments: | | | | | | | | | | |
Exelon Energy Delivery Company, LLC(b) | $ | 1,670 |
| | $ | 1,041 |
| | $ | 1,079 |
| $ | 1,835 |
| | $ | 1,670 |
| | $ | 1,041 |
|
PCI | 1 |
| | 6 |
| | — |
| (17 | ) | | 1 |
| | 6 |
|
BSC | 1 |
| | 1 |
| | — |
| — |
| | 1 |
| | 1 |
|
UII, LLC | 41 |
| | (9 | ) | | 20 |
| — |
| | 41 |
| | (9 | ) |
Exelon Transmission Company, LLC | (10 | ) | | (13 | ) | | (8 | ) | 1 |
| | (10 | ) | | (13 | ) |
Exelon Enterprise | 1 |
| | (1 | ) | | (1 | ) | — |
| | 1 |
| | (1 | ) |
Generation | 2,694 |
| | 496 |
| | 1,371 |
| 369 |
| | 2,710 |
| | 483 |
|
Total equity in earnings of investments | $ | 4,398 |
| | $ | 1,521 |
| | $ | 2,461 |
| |
Total equity in earnings of investments: | | $ | 2,188 |
| | $ | 4,414 |
| | $ | 1,508 |
|
| | | | | | | | | | |
Cash contributions received from affiliates | $ | 1,879 |
| | $ | 1,912 |
| | $ | 3,209 |
| $ | 2,302 |
| | $ | 1,879 |
| | $ | 1,912 |
|
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
| | | December 31, | December 31, |
(in millions) | 2017 | | 2016 | 2018 | | 2017 |
Accounts receivable from affiliates (current): | | | | | | |
BSC(a) | $ | 1 |
| | $ | 15 |
| $ | 13 |
| | $ | 1 |
|
Generation | 21 |
| | 22 |
| 17 |
| | 21 |
|
ComEd | 3 |
| | 3 |
| 4 |
| | 3 |
|
PECO | 1 |
| | 1 |
| 2 |
| | 1 |
|
BGE | 1 |
| | 1 |
| 2 |
| | 1 |
|
PHISCO | 6 |
| | 6 |
| 6 |
| | 6 |
|
Total accounts receivable from affiliates (current) | $ | 33 |
| | $ | 48 |
| |
Total accounts receivable from affiliates (current): | | $ | 44 |
| | $ | 33 |
|
Notes receivable from affiliates (current): | | | | | | |
BSC(a) | $ | 217 |
| | $ | 88 |
| $ | 116 |
| | $ | 217 |
|
Generation(c) | | 100 |
| | — |
|
Total notes receivable from affiliates (current): | | $ | 216 |
| | $ | 217 |
|
Investments in affiliates: | | | | | | |
BSC(a) | $ | 196 |
| | $ | 194 |
| $ | 197 |
| | $ | 196 |
|
Exelon Energy Delivery Company, LLC(b) | 25,082 |
| | 23,003 |
| 26,702 |
| | 25,082 |
|
PCI | 78 |
| | 77 |
| 61 |
| | 78 |
|
UII, LLC | 268 |
| | 92 |
| 268 |
| | 268 |
|
Exelon Transmission Company, LLC | 1 |
| | 5 |
| 1 |
| | 1 |
|
Voluntary Employee Beneficiary Association trust | (4 | ) | | (5 | ) | (1 | ) | | (4 | ) |
Exelon Enterprises | 22 |
| | 21 |
| 22 |
| | 22 |
|
Generation | 13,635 |
| | 11,488 |
| 13,204 |
| | 13,674 |
|
Other | (6 | ) | | (6 | ) | (6 | ) | | (6 | ) |
Total investments in affiliates | $ | 39,272 |
| | $ | 34,869 |
| |
Total investments in affiliates: | | $ | 40,448 |
| | $ | 39,311 |
|
Notes receivable from affiliates (non-current): | | | | | | |
Generation(c) | $ | 910 |
| | $ | 922 |
| $ | 898 |
| | $ | 910 |
|
Accounts payable to affiliates (current): | | | | | | |
ComEd | $ | — |
| | $ | 345 |
| |
UII, LLC | 360 |
| | 361 |
| $ | 360 |
| | $ | 360 |
|
Total accounts payable to affiliates (current) | $ | 360 |
| | $ | 706 |
| |
__________
| |
(a) | Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. |
| |
(b) | Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. |
| |
(c) | In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliate onaffiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation onin Exelon’s Consolidated Balance Sheets. |
Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts(a) | | | $ | 322 |
|
| $ | 159 |
|
| $ | 35 |
| (c) | $ | 197 |
| (e) | $ | 319 |
|
Deferred tax valuation allowance | | | 37 |
|
| — |
|
| 5 |
|
| 7 |
| | 35 |
|
Reserve for obsolete materials | | | 174 |
|
| 25 |
|
| (31 | ) | (d) | 12 |
| | 156 |
|
For the year ended December 31, 2017 | | | | | | | | | | | |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts(a) | | $ | 334 |
|
| $ | 126 |
|
| $ | 27 |
| (c) | $ | 165 |
| (d) | $ | 322 |
| | $ | 334 |
|
| $ | 126 |
|
| $ | 27 |
| (c) | $ | 165 |
| (e) | $ | 322 |
|
Deferred tax valuation allowance | | 20 |
|
| — |
|
| 17 |
|
| — |
| | 37 |
| | 20 |
|
| — |
|
| 17 |
|
| — |
| | 37 |
|
Reserve for obsolete materials | | 113 |
|
| 56 |
|
| 10 |
|
| 5 |
| | 174 |
| | 113 |
|
| 56 |
|
| 10 |
|
| 5 |
| | 174 |
|
For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts(a) | | $ | 284 |
|
| $ | 162 |
|
| $ | 99 |
| (b)(c) | $ | 211 |
| (d) | $ | 334 |
| | $ | 284 |
|
| $ | 162 |
|
| $ | 99 |
| (b)(c) | $ | 211 |
| (e) | $ | 334 |
|
Deferred tax valuation allowance | | 13 |
|
| — |
|
| 10 |
| (b) | 3 |
| | 20 |
| | 13 |
|
| — |
|
| 10 |
| (b) | 3 |
| | 20 |
|
Reserve for obsolete materials | | 105 |
|
| 12 |
|
| 1 |
| (b) | 5 |
| | 113 |
| | 105 |
|
| 12 |
|
| 1 |
| (b) | 5 |
| | 113 |
|
For the year ended December 31, 2015 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 311 |
|
| $ | 113 |
|
| $ | 27 |
| (c) | $ | 167 |
| (d) | $ | 284 |
| |
Deferred tax valuation allowance | | 50 |
|
| — |
|
| (27 | ) |
| 10 |
| | 13 |
| |
Reserve for obsolete materials | | 95 |
|
| 10 |
|
| 2 |
|
| 2 |
| | 105 |
| |
__________
| |
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, $23 million, and $8$23 million for the years ended December 31, 2018, 2017 2016, and 2015,2016, respectively. |
| |
(b) | Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger |
| |
(c) | Includes charges for late payments and non-service receivables. |
| |
(d) | Primarily reflects the reclassification of assets as held for sale. |
| |
(e) | Write-off of individual accounts receivable. |
Exelon Generation Company, LLC and Subsidiary Companies
(2) Generation
|
| | |
1.(i) | | Financial Statements:Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
| |
| | Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Notes to Consolidated Financial Statements |
| |
2.(ii) | | Financial Statement Schedules:Schedule: |
| |
| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Exelon Generation Company, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 114 |
|
| $ | 44 |
|
| $ | 4 |
|
| $ | 58 |
| | $ | 104 |
|
Deferred tax valuation allowance | | | 23 |
|
| — |
|
| 3 |
| | — |
| | 26 |
|
Reserve for obsolete materials | | | 166 |
|
| 20 |
|
| (32 | ) | (a) | 9 |
| | 145 |
|
For the year ended December 31, 2017 | | | | | | | | | | | |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 91 |
|
| $ | 34 |
|
| $ | — |
| | $ | 11 |
| | $ | 114 |
| | $ | 91 |
|
| $ | 34 |
|
| $ | — |
| | $ | 11 |
| | $ | 114 |
|
Deferred tax valuation allowance | | 9 |
|
| — |
|
| 14 |
| | — |
| | 23 |
| | 9 |
|
| — |
|
| 14 |
| | — |
| | 23 |
|
Reserve for obsolete materials | | 106 |
|
| 51 |
|
| 9 |
| | — |
| | 166 |
| | 106 |
|
| 51 |
|
| 9 |
| | — |
| | 166 |
|
For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 77 |
|
| $ | 19 |
|
| $ | 3 |
| | $ | 8 |
| | $ | 91 |
| | $ | 77 |
|
| $ | 19 |
|
| $ | 3 |
|
| $ | 8 |
| | $ | 91 |
|
Deferred tax valuation allowance | | 11 |
|
| — |
|
| — |
| | 2 |
| | 9 |
| | 11 |
| | — |
| | — |
| | 2 |
| | 9 |
|
Reserve for obsolete materials | | 102 |
|
| 6 |
|
| — |
| | 2 |
| | 106 |
| | 102 |
|
| 6 |
|
| — |
|
| 2 |
| | 106 |
|
For the year ended December 31, 2015 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts | | $ | 60 |
|
| $ | 22 |
|
| $ | — |
|
| $ | 5 |
| | $ | 77 |
| |
Deferred tax valuation allowance | | 48 |
| | — |
| | (27 | ) | | 10 |
| | 11 |
| |
Reserve for obsolete materials | | 93 |
|
| 9 |
|
| — |
|
| — |
| | 102 |
| |
__________
| |
(a) | Primarily reflects the reclassification of assets as held for sale. |
Commonwealth Edison Company and Subsidiary Companies
(3) ComEd
|
| | |
1.(i) | | Financial Statements:Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
| |
| | Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Notes to Consolidated Financial Statements |
| |
2.(ii) | | Financial Statement Schedules:Schedule: |
| |
| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 73 |
|
| $ | 44 |
|
| $ | 23 |
| (a) | $ | 59 |
| (b) | $ | 81 |
|
Reserve for obsolete materials | | | 5 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 6 |
|
For the year ended December 31, 2017 | | | | | | | | | | | |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 70 |
|
| $ | 39 |
|
| $ | 20 |
| (a) | $ | 56 |
| (b) | $ | 73 |
| | $ | 70 |
|
| $ | 39 |
|
| $ | 20 |
| (a) | $ | 56 |
| (b) | $ | 73 |
|
Reserve for obsolete materials | | 4 |
|
| 3 |
|
| 1 |
| | 3 |
| | 5 |
| | 4 |
|
| 3 |
|
| 1 |
|
| 3 |
| | 5 |
|
For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 75 |
|
| $ | 45 |
|
| $ | 23 |
| (a) | $ | 73 |
| (b) | $ | 70 |
| | $ | 75 |
|
| $ | 45 |
|
| $ | 23 |
| (a) | $ | 73 |
| (b) | $ | 70 |
|
Reserve for obsolete materials | | 3 |
|
| 4 |
|
| 1 |
| | 4 |
| | 4 |
| | 3 |
|
| 4 |
|
| 1 |
|
| 4 |
| | 4 |
|
For the year ended December 31, 2015 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts | | $ | 84 |
|
| $ | 39 |
|
| $ | 18 |
| (a) | $ | 66 |
| (b) | $ | 75 |
| |
Reserve for obsolete materials | | 2 |
|
| 1 |
|
| 2 |
| | 2 |
| | 3 |
| |
__________
| |
(a) | Primarily charges for late payments and non-service receivables. |
| |
(b) | Write-off of individual accounts receivable. |
PECO Energy Company and Subsidiary Companies
(4) PECO
|
| | |
1.(i) | | Financial Statements:Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
| |
| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Notes to Consolidated Financial Statements |
| |
2.(ii) | | Financial Statement Schedules:Schedule: |
| |
| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts(a) | | | $ | 56 |
|
| $ | 33 |
|
| $ | 3 |
| (b) | $ | 31 |
| (c) | $ | 61 |
|
Reserve for obsolete materials | | | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
|
For the year ended December 31, 2017 | | | | | | | | | | | |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts(a) | | $ | 61 |
|
| $ | 26 |
|
| $ | 4 |
| (b) | $ | 35 |
| (c) | $ | 56 |
| | $ | 61 |
|
| $ | 26 |
|
| $ | 4 |
| (b) | $ | 35 |
| (c) | $ | 56 |
|
Reserve for obsolete materials | | 2 |
|
| — |
|
| — |
| | — |
| | 2 |
| | 2 |
|
| — |
|
| — |
|
| — |
| | 2 |
|
For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts(a) | | $ | 83 |
|
| $ | 32 |
|
| $ | 7 |
| (b) | $ | 61 |
| (c) | $ | 61 |
| | $ | 83 |
|
| $ | 32 |
|
| $ | 7 |
| (b) | $ | 61 |
| (c) | $ | 61 |
|
Reserve for obsolete materials | | 1 |
|
| 1 |
|
| — |
| | — |
| | 2 |
| | 1 |
|
| 1 |
|
| — |
|
| — |
| | 2 |
|
For the year ended December 31, 2015 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts(a) | | $ | 100 |
|
| $ | 37 |
|
| $ | 9 |
| (b) | $ | 63 |
| (c) | $ | 83 |
| |
Reserve for obsolete materials | | 1 |
|
| — |
|
| — |
| | — |
| | 1 |
| |
__________
| |
(a) | Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, $23 million, and $8$23 million for the years ended December 31, 2018, 2017, 2016, and 2015,2016, respectively. |
| |
(b) | Primarily charges for late payments. |
| |
(c) | Write-off of individual accounts receivable. |
Baltimore Gas and Electric Company and Subsidiary Companies
(5) BGE
|
| | |
1.(i) | | Financial Statements:Statements (Item 8): |
| |
| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
| |
| | Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
| |
| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
| |
| | Notes to Consolidated Financial Statements |
| |
2.(ii) | | Financial Statement Schedules:Schedule: |
| |
| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
| |
| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 24 |
|
| $ | 10 |
|
| $ | (2 | ) |
| $ | 12 |
| (a) | $ | 20 |
|
Deferred tax valuation allowance | | | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
|
Reserve for obsolete materials | | | — |
|
| 1 |
|
| — |
|
| — |
| | 1 |
|
For the year ended December 31, 2017 | | | | | | | | | | | |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 32 |
|
| $ | 8 |
|
| $ | (3 | ) |
| $ | 13 |
| (a) | $ | 24 |
| | $ | 32 |
|
| $ | 8 |
|
| $ | (3 | ) |
| $ | 13 |
| (a) | $ | 24 |
|
Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
| | — |
| | 1 |
| | 1 |
|
| — |
|
| — |
|
| — |
| | 1 |
|
Reserve for obsolete materials | | — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
|
| — |
|
| — |
|
| — |
| | — |
|
For the year ended December 31, 2016 | |
|
|
|
|
|
|
| |
|
| |
|
|
|
|
|
|
| |
|
|
Allowance for uncollectible accounts | | $ | 49 |
|
| $ | 1 |
|
| $ | 9 |
|
| $ | 27 |
| (a) | $ | 32 |
| | $ | 49 |
|
| $ | 1 |
|
| $ | 9 |
|
| $ | 27 |
| (a) | $ | 32 |
|
Deferred tax valuation allowance | | 1 |
|
| — |
|
| — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
Reserve for obsolete materials | | — |
|
| — |
|
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
For the year ended December 31, 2015 | |
|
|
|
|
|
|
| |
|
| |
Allowance for uncollectible accounts | | $ | 67 |
|
| $ | 15 |
|
| $ | — |
|
| $ | 33 |
| (a) | $ | 49 |
| |
Deferred tax valuation allowance | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| |
Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Write-off of individual accounts receivable. |
Pepco Holdings LLC and Subsidiary Companies
(6) PHI
|
| | |
1.(i) | | Successor Company Financial Statements:Statements (Item 8): |
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| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
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| | Consolidated Statements of Operations and Comprehensive Income (Loss) for the YearYears Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016 |
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| | Consolidated Statements of Cash Flows for the YearYears Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016 |
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| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
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| | Consolidated Statements of Changes in Equity for the YearYears Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016 |
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| | Notes to Consolidated Financial Statements |
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(ii) | | Predecessor Company Financial Statements:Statements (Item 8): |
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| | Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP |
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| | Consolidated Statements of Operations and Comprehensive Income (Loss) for the Period January 1, 2016 to March 23, 2016 and the Year Ended December 31, 2015 |
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| | Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016 and for the Year Ended December 31, 2015 |
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| | Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016 and for the Year Ended December 31, 2015 |
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| | Notes to Consolidated Financial Statements |
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2.(iii) | | Successor Financial Statement Schedules:Schedule: |
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| | Schedule II – Valuation and Qualifying Accounts - For the YearYears Ended December 31, 2018 and 2017 and the Period March 24, 2016 to December 31, 2016 |
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(iv) | | Predecessor Financial Statement Schedules:Schedule: |
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| | Schedule II – Valuation and Qualifying Accounts - For the Period January 1, 2016 to March 23, 2016 and For the Year Ended December 31, 2015 |
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| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Pepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the Year Ended December 31, 2018 (Successor) | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 55 |
| | $ | 28 |
| | $ | 7 |
| (a) | $ | 37 |
| (b) | $ | 53 |
|
Deferred tax valuation allowance | | | 13 |
| | — |
| | 2 |
| | 7 |
| | 8 |
|
Reserve for obsolete materials | | | 2 |
| | — |
| | — |
| | — |
| | 2 |
|
For the Year Ended December 31, 2017 (Successor) | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 80 |
| | $ | 19 |
| | $ | 6 |
| (a) | $ | 50 |
| (b) | $ | 55 |
| | $ | 80 |
| | $ | 19 |
| | $ | 6 |
| (a) | $ | 50 |
| (b) | $ | 55 |
|
Deferred tax valuation allowance | | 10 |
| | — |
| | 3 |
| | — |
| | 13 |
| | 10 |
| | — |
| | 3 |
| | — |
| | 13 |
|
Reserve for obsolete materials | | 2 |
| | 2 |
| | — |
| | 2 |
| | 2 |
| | 2 |
| | 2 |
| | — |
| | 2 |
| | 2 |
|
March 24, 2016 to December 31, 2016 (Successor) | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 52 |
| | $ | 65 |
| | $ | 5 |
| (a) | $ | 42 |
| (b) | $ | 80 |
| | $ | 52 |
| | $ | 65 |
| | $ | 5 |
| (a) | $ | 42 |
| (b) | $ | 80 |
|
Deferred tax valuation allowance | | 63 |
| | — |
| | (53 | ) | | — |
| | 10 |
| | 63 |
| | — |
| | (53 | ) | | — |
| | 10 |
|
Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | (1 | ) | | 2 |
| | — |
| | 1 |
| | — |
| | (1 | ) | | 2 |
|
January 1, 2016 to March 23, 2016 (Predecessor) | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 56 |
| | $ | 16 |
| | $ | 2 |
| (a) | $ | 22 |
| (b) | $ | 52 |
| | $ | 56 |
| | $ | 16 |
| | $ | 2 |
| (a) | $ | 22 |
| (b) | $ | 52 |
|
Deferred tax valuation allowance | | 63 |
| | — |
| | — |
| | — |
| | 63 |
| | 63 |
| | — |
| | — |
| | — |
| | 63 |
|
Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | ��� |
| | — |
|
For the Year Ended December 31, 2015 (Predecessor) | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 40 |
| | $ | 59 |
| | $ | 5 |
| (a) | $ | 48 |
| (b) | $ | 56 |
| |
Deferred tax valuation allowance | | 61 |
| | — |
| | 2 |
| | — |
| | 63 |
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Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
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__________
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(a) | Primarily charges for late payments. |
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(b) | Write-off of individual accounts receivable. |
Potomac Electric Power Company
(7) Pepco
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1.(i) | | Financial Statements:Statements (Item 8): |
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| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
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| | Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Balance Sheets at December 31, 20172018 and 20162017 |
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| | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Notes to Consolidated Financial Statements |
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2.(ii) | | Financial Statement Schedules:Schedule: |
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| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
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| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 21 |
| | $ | 11 |
| | $ | 3 |
| (a) | $ | 14 |
| (b) | $ | 21 |
|
Reserve for obsolete materials | | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 29 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 21 |
| | $ | 29 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 21 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
| | 1 |
| | 1 |
| | — |
| | 1 |
| | 1 |
|
For the year ended December 31, 2016 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 17 |
| | $ | 29 |
| | $ | 3 |
| (a) | $ | 20 |
| (b) | $ | 29 |
| | $ | 17 |
| | $ | 29 |
| | $ | 3 |
| (a) | $ | 20 |
| (b) | $ | 29 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | 3 |
| | — |
| | 2 |
| | 1 |
| | — |
| | 3 |
| | — |
| | 2 |
| | 1 |
|
For the year ended December 31, 2015 | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 16 |
| | $ | 20 |
| | $ | 1 |
| (a) | $ | 20 |
| (b) | $ | 17 |
| |
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| |
__________
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(a) | Primarily charges for late payments. |
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(b) | Write-off of individual accounts receivable. |
Delmarva Power & Light Company
(8) DPL
|
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1.(i) | | Financial Statements:Statements (Item 8): |
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| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
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| | Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Balance Sheets at December 31, 20172018 and 20162017 |
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| | Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Notes to Consolidated Financial Statements |
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2.(ii) | | Financial Statement Schedules:Schedule: |
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| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
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| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 16 |
| | $ | 6 |
| | $ | 2 |
| (a) | $ | 11 |
| (b) | $ | 13 |
|
Reserve for obsolete materials | | | — |
| | — |
| | — |
| | — |
| | — |
|
For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 24 |
| | $ | 3 |
| | $ | 2 |
| (a) | $ | 13 |
| (b) | $ | 16 |
| | $ | 24 |
| | $ | 3 |
| | $ | 2 |
| (a) | $ | 13 |
| (b) | $ | 16 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
For the year ended December 31, 2016 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 17 |
| | $ | 23 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 24 |
| | $ | 17 |
| | $ | 23 |
| | $ | 2 |
| (a) | $ | 18 |
| (b) | $ | 24 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
|
For the year ended December 31, 2015 | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 11 |
| | $ | 20 |
| | $ | 2 |
| (a) | $ | 16 |
| (b) | $ | 17 |
| |
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
Atlantic City Electric Company and Subsidiary Company
(9) ACE
|
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1.(i) | | Financial Statements:Statements (Item 8): |
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| | Report of Independent Registered Public Accounting Firm dated February 9, 20188, 2019 of PricewaterhouseCoopers LLP |
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| | Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Consolidated Balance Sheets at December 31, 20172018 and 20162017 |
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| | Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 2016 and 20152016 |
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| | Notes to Consolidated Financial Statements |
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2.(ii) | | Financial Statement Schedules:Schedule: |
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| | Schedule II – II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016 |
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| | Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto |
Atlantic City Electric Company and Subsidiary Company
Schedule II – Valuation and Qualifying Accounts
| | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | Additions and adjustments | | | | | | | | Additions and adjustments | | | | |
Description | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period | | Balance at Beginning of Period | | Charged to Costs and Expenses | | Charged to Other Accounts | | Deductions | | Balance at End of Period |
| | (in millions) | | (in millions) |
For the year ended December 31, 2018 | | | | | | | | | | | |
Allowance for uncollectible accounts | | | $ | 18 |
| | $ | 11 |
| | $ | 2 |
| (a) | $ | 12 |
| (b) | $ | 19 |
|
Reserve for obsolete materials | | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
For the year ended December 31, 2017 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 27 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 19 |
| (b) | $ | 18 |
| | $ | 27 |
| | $ | 8 |
| | $ | 2 |
| (a) | $ | 19 |
| (b) | $ | 18 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | 1 |
| | — |
| | — |
| | — |
| | 1 |
| | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
For the year ended December 31, 2016 | | | | | | | | | | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 17 |
| | $ | 32 |
| | $ | 2 |
| (a) | $ | 24 |
| (b) | $ | 27 |
| | $ | 17 |
| | $ | 32 |
| | $ | 2 |
| (a) | $ | 24 |
| (b) | $ | 27 |
|
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | 1 |
| | — |
| | — |
| | 1 |
| | — |
| | 1 |
| | — |
| | — |
| | 1 |
|
For the year ended December 31, 2015 | | | | | | | | | | | |
Allowance for uncollectible accounts | | $ | 9 |
| | $ | 18 |
| | $ | 2 |
| (a) | $ | 12 |
| (b) | $ | 17 |
| |
Deferred tax valuation allowance | | — |
| | — |
| | — |
| | — |
| | — |
| |
Reserve for obsolete materials | | — |
| | — |
| | — |
| | — |
| | — |
| |
__________
| |
(a) | Primarily charges for late payments. |
| |
(b) | Write-off of individual accounts receivable. |
Exhibits required by Item 601 of Regulation S-K:
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to furnish a copy of any such instrument to the Commission upon request.
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Exhibit No. | Description | | | | |
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| Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 8, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). |
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Exhibit No. | Description |
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4-1 | First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registration No. 2-2281, Exhibit B-1).(a) |
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4-1-2 | Reserved. |
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4-1-3 | Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage: |
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| Dated as of | | File Reference | | Exhibit No. |
| May 1, 1927 | | 2-2881(a) | | B-1(c) |
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| March 1, 1937 | | 2-2881(a) | | B-1(g) |
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| December 1, 1941 | | 2-4863(a) | | B-1(h) |
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| November 1, 1944 | | 2-5472(a) | | B-1(i) |
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| December 1, 1946 | | 2-6821(a) | | 7-1(j) |
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| September 1, 1957 | | 2-13562(a) | | 2(b)-17 |
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| May 1, 1958 | | 2-14020(a) | | 2(b)-18 |
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| March 1, 1968 | | 2-34051(a) | | 2(b)-24 |
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| March 1, 1981 | | 2-72802(a) | | 4-46 |
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| March 1, 1981 | | 2-72802(a) | | 4-47 |
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| December 1, 1984 | | 1-01401, 1984 Form 10-K(a) | | 4-2(b) |
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| March 1, 1993 | | 1-01401, 1992 Form 10-K(a) | | 4(e)-86 |
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| Dated as of | | File Reference | | Exhibit No. |
| May 1, 1993 | | 1-01401, March 31, 1993 Form 10-Q(a) | | 4(e)-88 |
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| May 1, 1993 | | 1-01401, March 31, 1993 Form 10-Q(a) | | 4(e)-89 |
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| April 15, 2004 | | 0-6844, September 30, 2004 Form 10-Q(a) | | 4-1-1 |
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| September 15, 2006 | | | | |
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| March 1, 2007 | | | | |
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| March 15, 2009 | | | | |
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| September 1, 2012 | | | | |
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| September 15, 2013 | | | | |
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| September 1, 2014 | |
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| September 15, 2015 | |
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| September 1, 2016 | | | | |
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| September 1, 2017 | | | | |
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| February 1, 2018 | |
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| September 1, 2018 | | | | |
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Exhibit No. | Description |
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4-3 | Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1).(a) |
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4-3-1 | Supplemental Indentures to Commonwealth Edison Company Mortgage. |
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| Dated as of | | File Reference | | Exhibit No. |
| August 1, 1946 | | 2-60201, Form S-7(a) | | 2-1 |
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| April 1, 1953 | | 2-60201, Form S-7(a) | | 2-1 |
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| March 31, 1967 | | 2-60201, Form S-7(a) | | 2-1 |
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| Dated as of | | File Reference | | Exhibit No. |
| April 1, 1967 | | 2-60201, Form S-7(a) | | 2-1 |
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| February 28, 1969 | | 2-60201, Form S-7(a) | | 2-1 |
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| May 29, 1970 | | 2-60201, Form S-7(a) | | 2-1 |
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| June 1, 1971 | | 2-60201, Form S-7(a) | | 2-1 |
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| Dated as of | | File Reference | | Exhibit No. |
| April 1, 1972 | | 2-60201, Form S-7(a) | | 2-1 |
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| May 31, 1972 | | 2-60201, Form S-7(a) | | 2-1 |
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| June 15, 1973 | | 2-60201, Form S-7(a) | | 2-1 |
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| May 31, 1974 | | 2-60201, Form S-7(a) | | 2-1 |
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| June 13, 1975 | | 2-60201, Form S-7(a) | | 2-1 |
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| May 28, 1976 | | 2-60201, Form S-7(a) | | 2-1 |
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| June 3, 1977 | | 2-60201, Form S-7(a) | | 2-1 |
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| May 17, 1978 | | 2-99665, Form S-3(a) | | 4-3 |
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| August 31, 1978 | | 2-99665, Form S-3(a) | | 4-3 |
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| June 18, 1979 | | 2-99665, Form S-3(a) | | 4-3 |
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| June 20, 1980 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 16, 1981 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 30, 1982 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 15, 1983 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 13, 1984 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 15, 1985 | | 2-99665, Form S-3(a) | | 4-3 |
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| April 15, 1986 | | 33-6879, Form S-3(a) | | 4-9 |
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| January 13, 2003 | | | | |
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| February 22, 2006 | | | | |
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| August 1, 2006 | | | | |
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| September 15, 2006 | | | | |
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| March 1, 2007 | | | | |
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| August 30, 2007 | | | | |
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| December 20, 2007 | | | | |
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| March 10, 2008 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| July 12, 2010 | | | | |
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| August 22, 2011 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| September 17, 2012 | | | | |
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| August 1, 2013 | | | | |
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| January 2, 2014 | | | | |
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| October 28, 2014 | | | | |
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| February 18, 2015 | | | | |
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| November 4, 2015 | | | | |
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| June 15, 2016 | | | | |
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| August 9, 2017 | | | | |
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| February 6, 2018 | | | | |
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| July 26, 2018 | | | | |
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Exhibit No. | Description |
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4-4 | Indenture dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A. (U.S. Bank National Association, as current successor trustee), Trustee relating to Notes (Registration No. 33-20619, Form S-3, Exhibit 4-13).(a) |
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Exhibit No. | Description |
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| Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1). |
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Exhibit No. | Description |
4-27 | Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Baltimore Gas and Electric Company, File No. 1-1910).(a) |
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| Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). |
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Exhibit No. | Description |
| Officers’ Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc., with the form of Notes attached thereto. (Designated as Exhibit No. 4 (b) to the Current Report on Form 8-K dated December 14, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). |
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Exhibit No. | Description |
4-42 | Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936 (File No. 2-2232, Registration Statement dated June 19, 1936, Exhibit B-4)(a) |
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4-42-1 | Supplemental Indentures to Potomac Electric Power Company Mortgage. |
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| Dated as of | | File Reference | | Exhibit No. |
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| December 10, 1939 | | Form 8-K, 1/3/40(a) | | B |
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| Dated as of | | File Reference | | Exhibit No. |
| July 15, 1942 | | 2-5032, Amendment No 2. To Registration Statement, 8/24/42(a) | | B-1 |
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| October 15, 1947 | | Form 8-K , 12/8/47(a) | | A |
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| December 31, 1948 | | Form 10-K, 4/13/49(a) | | A-2 |
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| December 31, 1949 | | Form 8-K, 2/8/50(a) | | (a)-1 |
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| February 15, 1951 | | Form 8-K, 3/9/51(a) | | (a) |
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| February 16, 1953 | | Form 8-K, 3/5/53(a) | | (a)-1 |
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| March 15, 1954 and March 15, 1955 | | 2-11627, Registration Statement, 5/2/55(a) | | 4-B |
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| March 15, 1956 | | Form 10-K, 4/4/56(a) | | C |
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| April 1, 1957 | | 2-13884, Registration Statement, 2/5/58(a) | | 4-B |
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| May 1, 1958 | | 2-14518, Registration Statement, 11/10/58(a) | | 2-B |
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| May 1, 1959 | | 2-15027, Amendment No. 1 to Registration Statement, 5/13/59(a) | | 4-B |
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| May 2, 1960 | | 2-17286, Registration Statement, 11/9/60(a) | | 2-B |
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| April 3, 1961 | | Form 10-K, 4/24/61(a) | | A-1 |
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| May 1, 1962 | | 2-21037, Registration Statement, 1/25/63(a) | | 2-B |
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| May 1, 1963 | | 2-21961, Registration Statement, 12/19/63(a) | | 4-B |
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| April 23, 1964 | | 2-22344, Registration Statement, 4/24/64(a) | | 2-B |
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| May 3, 1965 | | 2-24655, Registration Statement, 3/16/66(a) | | 2-B |
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| June 1, 1966 | | Form 10-K, 4/11/67(a) | | 1 |
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| April 28, 1967 | | 2-26356, Post-Effective Amendment No. 1 to Registration Statement, 5/3/67(a) | | 2-B |
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| Dated as of | | File Reference | | Exhibit No. |
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| July 3, 1967 | | 2-28080, Registration Statement, 1/25/68(a) | | 2-B |
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| May 1, 1968 | | 2-31896, Registration Statement, 2/28/69(a) | | 2-B |
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| June 16, 1969 | | 2-36094, Registration Statement, 1/27/70(a) | | 2-B |
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| Dated as of | | File Reference | | Exhibit No. |
| May 15, 1970 | | 2-38038, Registration Statement, 7/27/70(a) | | 2-B |
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| September 1, 1971 | | 2-45591, Registration Statement, 9/1/72(a) | | 2-C |
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| June 17, 1981 | | Amendment No. 1 to Form 8-A, 6/18/81(a) | | 2 |
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| November 1, 1985 | | Form 8-A, 11/1/85(a) | | 2B |
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| September 16, 1987 | | 33-18229, Registration Statement, 10/30/87(a) | | 4-B |
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| May 1, 1989 | | 33-29382, Registration Statement, 6/16/89(a) | | 4-C |
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| May 21, 1991 | | Form 10-K, 3/27/92(a) | | 4 |
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| May 7, 1992 | | Form 10-K, 3/26/93(a) | | 4 |
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| September 1, 1992 | | Form 10-K, 3/26/93(a) | | 4 |
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| November 1, 1992 | | Form 10-K, 3/26/93(a) | | 4 |
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| July 1, 1993 | | 33-49973, Registration Statement, 8/11/93(a) | | 4.4 |
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| February 10, 1994 | | | | |
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| February 11, 1994 | | | | |
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| October 2, 1997 | | | | |
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| November 17, 2003 | | | | |
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| March 16, 2004 | | | | |
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| May 24, 2005 | | | | |
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| April 1, 2006 | | | | |
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| November 13, 2007 | | | | |
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| March 24, 2008 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| December 3, 2008 | | | | |
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| March 28, 2012 | | | | |
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| March 11, 2013 | | | | |
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| November 14, 2013 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| March 11, 2014 | | | | |
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| March 9, 2015 | | | | |
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| May 15, 2017 | | | | |
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| June 1, 2018 | | | |
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Exhibit No. | Description |
4-43 | Indenture, dated as of July 28, 1989, between Potomac Electric Power Company and The Bank of New York Mellon, Trustee, with respect to Medium-Term Note Program (File No. 001-01072, Form 8-K dated June 21, 1990, Exhibit 4)(a) |
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4-45 | Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto (File No. 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-A)(a) |
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4-45-1 | Supplemental Indentures to Delmarva Power & Light Company Mortgage. |
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| Dated as of | | File Reference | | Exhibit No. |
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| January 1, 1986 | | 33-39756, Registration Statement, 4/03/91(a) | | 4-B |
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| June 1, 1986 | | 33-24955, Registration Statement, 10/13/88(a) | | 4-B |
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| January 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a) | | 4-B |
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| September 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a) | | 4-B |
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| October 1, 1987 | | 33-24955, Registration Statement, 10/13/88(a) | | 4-B |
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| January 1, 1988 | | 33-24955, Registration Statement, 10/13/88(a) | | 4-B |
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| Dated as of | | File Reference | | Exhibit No. |
| December 1, 1988 | | 33-39756, Registration Statement, 4/03/91(a) | | 4-D |
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| January 1, 1989 | | 33-39756, Registration Statement, 4/03/91(a) | | 4-E |
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| March 1, 1990 | | 33-39756, Registration Statement, 4/03/91(a) | | 4-F |
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| January 1, 1991 | | 33-46892, Registration Statement, 4/1/92(a) | | 4-E |
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| July 1, 1991 | | 33-46892, Registration Statement, 4/1/92(a) | | 4-F |
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| Dated as of | | File Reference | | Exhibit No. |
| February 1, 1992 | | 33-49750, Registration Statement, 7/17/92(a) | | 4 |
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| May 1, 1992 | | 33-57652, Registration Statement, 1/29/93(a) | | 4-G |
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| October 1, 1992 | | 33-63582, Registration Statement, 5/28/93(a) | | 4-H |
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| January 1, 1993 | | 33-50453, Registration Statement, 10/1/93(a) | | 99 |
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| June 1, 1993 | | 33-53855, Registration Statement, 1/30/95(a) | | 4-J |
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| July 1, 1993 | | 33-53855, Registration Statement, 1/30/95(a) | | 4-K |
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| October 1, 1993 | | 33-53855, Registration Statement, 1/30/95(a) | | 4-L |
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| January 1, 1994 | | 33-53855, Registration Statement, 1/30/95(a) | | 4-M |
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| October 1, 1994 | | 33-53855, Registration Statement, 1/30/95(a) | | 4-N |
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| January 1, 1995 | | 333-00505, Registration Statement, 1/29/96(a) | | 4-K |
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| June 1, 1995 | | 333-00505, Registration Statement, 1/29/96(a) | | 4-L |
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| January 1, 1996 | | 333-24059, Registration Statement, 3/27/97(a) | | 4-L |
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| January 1, 1997 | | | | |
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| January 1, 1998 | | | | |
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| January 1, 1999 | | | | |
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| January 1, 2000 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| January 1, 2001 | | | | |
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| January 1, 2002 | | | | |
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| January 1, 2003 | | | | |
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| January 1, 2004 | | | | |
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| January 1, 2005 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| January 1, 2006 | | | | |
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| January 1, 2007 | | | | |
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| January 1, 2008 | | | | |
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| January 1, 2009 | | | | |
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| September 22, 2009 | | | | |
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| January 1, 2010 | | | | |
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| January 1, 2011 | | | | |
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| May 2, 2011 | | | | |
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| January 1, 2012 | | | | |
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| June 19, 2012 | | | | |
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| January 1, 2013 | | | | |
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| November 7, 2013 | | | | |
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| January 1, 2014 | | | | |
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| June 2, 2014 | | | | |
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| January 1, 2015 | | | | |
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| May 4, 2015 | | | | |
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| January 1, 2016 | | Filed herewith. | | |
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| December 5, 2016 | | | | |
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| Dated as of | | File Reference | | Exhibit No. |
| April 5, 2017 | | | | |
| April 3, 2018 | | | | |
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| June 1, 2018 | | | | |
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Exhibit No. | Description | |
4-46 | Indenture between Delmarva Power & Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988 (File No. 33-46892, Registration Statement dated April 1, 1992, Exhibit 4-G)(a) |
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4-47 | Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon (formerly Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a))(a) |
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4-47-1 | Supplemental Indentures to Atlantic City Electric Company Mortgage. |
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| Dated as of | | File Reference | | Exhibit No. | |
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| June 1, 1949 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| July 1, 1950 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| November 1, 1950 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| March 1, 1952 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| January 1, 1953 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| March 1, 1954 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| March 1, 1955 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| January 1, 1957 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| April 1, 1958 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| April 1, 1959 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| March 1, 1961 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| July 1, 1962 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| March 1, 1963 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| Dated as of | | File Reference | | Exhibit No. | |
| February 1, 1966 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| April 1, 1970 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| September 1, 1970 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| May 1, 1971 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| April 1, 1972 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| June 1, 1973 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| January 1, 1975 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| May 1, 1975 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) |
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| Dated as of | | File Reference | | Exhibit No. |
| December 1, 1976 | | 2-66280, Registration Statement, 12/21/79(a) | | 2(b) | |
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| January 1, 1980 | | Form 10-K, 3/25/81(a) | | 4(e) | |
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| May 1, 1981 | | Form 10-Q, 8/10/81(a) | | 4(a) | |
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| November 1, 1983 | | Form 10-K, 3/30/84(a) | | 4(d) | |
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| April 15, 1984 | | Form 10-Q, 5/14/84(a) | | 4(a) | |
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| July 15, 1984 | | Form 10-Q, 8/13/84(a) | | 4(a) | |
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| October 1, 1985 | | Form 10-Q, 11/12/85(a) | | 4 | |
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| May 1, 1986 | | Form 10-Q, 5/12/86(a) | | 4 | |
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| July 15, 1987 | | Form 10-K, 3/28/88(a) | | 4(d) | |
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| October 1, 1989 | | Form 10-Q for quarter ended 9/30/89(A) | | 4(a) | |
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| March 1, 1991 | | Form 10-K, 3/28/91(a) | | 4(d)(1) | |
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| May 1, 1992 | | 33-49279, Registration Statement, 1/6/93(a) | | 4(b) | |
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| January 1, 1993 | | | | | |
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| August 1, 1993 | | Form 10-Q, 11/12/93(a) | | 4(a) | |
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| September 1, 1993 | | Form 10-Q, 11/12/93(a) | | 4(b) | |
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| November 1, 1993 | | Form 10-K, 3/29/94(a) | | 4(c)(1) | |
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| June 1, 1994 | | Form 10-Q, 8/14/94(a) | | 4(a) | |
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| October 1, 1994 | | Form 10-Q, 11/14/94(a) | | 4(a) | |
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| Dated as of | | File Reference | | Exhibit No. | |
| November 1, 1994 | | Form 10-K, 3/21/95(a) | | 4(c)(1) | |
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| March 1, 1997 | | | | | |
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| April 1, 2004 | | | | | |
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| August 10, 2004 | | | | | |
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| March 8, 2006 | | | | | |
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| November 6, 2008 | | | | | |
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| March 29, 2011 | | | | | |
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| August 18, 2014 | | | | | |
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| December 1, 2015 | | | | | |
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| October 9, 2018 | | | | | |
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Exhibit No. | Description |
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| Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.3) |
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Exhibit No. | Description |
| Credit Agreement, dated as of September 18, 2014, among ExGen Texas Power, LLC, ExGen Texas Power Holdings, LLC, Wolf Hollow I Power, LLC, Colorado Bend I Power, LLC, Laporte Power, LLC, Handley Power, LLC and Mountain Creek Power, LLC, the lenders party thereto from time to time, Bank of America, N.A., as administrative agent and collateral agent, and Wilmington Trust, National Association, as depositary agent. (File No. 1-16169, Form 8-K dated September 18, 2014, Exhibit 10.1). |
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10-4 | Reserved. |
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Exhibit No. | Description |
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10-33 | Reserved. |
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Exhibit No. | Description |
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| Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1). |
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Exhibit No. | Description |
| Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6). |
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Exhibit No. | Description |
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| Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International S.A. and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 12, 2009, filed by Constellation Energy Group, Inc., File No. 1-12869). |
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| Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(s) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). |
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Exhibit No. | Description |
| Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910). |
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| Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). |
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| Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F. International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869). |
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10-64 - 10-70 | Reserved. |
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| 364-Day Bridge Term Loan Agreement, dated as of May 30, 2014, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and Barclays Bank PLC, as Administrative Agent (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit No. 10.1).
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| Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Corporation, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.2).
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| Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Generation Company, LLC, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.3).
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| Amendment No. 3 to Credit Agreement, dated May 30, 2014, among PECO Energy Company, as Borrower, the financial institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.4).
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| Amendment No. 2 to Credit Agreement, dated as of May 30, 2014, among Baltimore Gas and Electric Company, as Borrower, the financial institutions signatory therein, as Lenders and The Royal Bank of Scotland plc, as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit 10.5).
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Exhibit No. | Description |
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| Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company, LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1) |
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| Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K dated March 10, 2015, Exhibit 1.1) |
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| Purchase Agreement, May 4, 2015, among Delmarva Power & Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-01405, Form 8-K dated May 5, 2015, Exhibit 1.1) |
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| $300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10) |
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| $500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10) |
| Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1) |
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Exhibit No. | Description |
| First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A., as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013, Exhibit 10.25.1) |
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Exhibit No. | Description |
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| Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 20, 2014, Exhibit 10.1) |
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| Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated May 1, 2015, Exhibit 10.1) |
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| Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.1) |
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| Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Corporation, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated May 27, 2016, Exhibit 99.1) |
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| Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.2) |
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| Amendment No. 74 to Credit Agreement, dated as of March 23, 2011, among Exelon GenerationCommonwealth Edison Company, LLC, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-K dated May 27, 2016, Exhibit 99.2)99.3) |
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Exhibit No. | Description |
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| Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated May 27, 2016, Exhibit 99.4) |
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| Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910, Form 8-K dated May 27, 2016, Exhibit 99.5) |
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| Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers, the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6) |
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Exhibit No. | Description |
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| Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among ExGen Renewables IV, LLC, ExGen Renewables IV Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and Exchange Commission pursuant to a request for confidential treatment.) |
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Exhibit No. | Description |
| Subsidiaries |
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| Consent of Independent Registered Public Accountants |
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Exhibit No. | Description |
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| Power of Attorney (Exelon Corporation) |
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24-11 | Reserved. |
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Exhibit No. | Description |
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| Power of Attorney (Commonwealth Edison Company) |
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24-23 | Reserved. |
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24-24 | Reserved. |
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| Power of Attorney (PECO Energy Company) |
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Exhibit No. | Description |
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| Reserved. |
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| Power of Attorney (Baltimore Gas and Electric Company) |
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| Power of Attorney (Pepco Holdings LLC) |
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| Power of Attorney (Potomac Electric Power Company) |
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| Power of Attorney (Delmarva Power & Light Company) |
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Exhibit No. | Description |
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| Power of Attorney (Atlantic City Electric Company) |
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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year ended December 31, 20172018 filed by the following officers for the following registrants: |
Exhibit No. | Description |
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Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December 31, 20172018 filed by the following officers for the following registrants: |
Exhibit No. | Description |
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Exhibit No. | Description |
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101.INS | XBRL Instance |
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101.SCH | XBRL Taxonomy Extension Schema |
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101.CAL | XBRL Taxonomy Extension Calculation |
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101.DEF | XBRL Taxonomy Extension Definition |
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101.LAB | XBRL Taxonomy Extension Labels |
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101.PRE | XBRL Taxonomy Extension Presentation |
__________
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* | Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees. |
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(a) | These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place. |
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ITEM 16. | FORM 10-K SUMMARY |
All Registrants
Registrants may voluntarily include a summary of information required by Form 10-K under this Item 16. The Registrants have elected not to include such summary information.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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EXELON CORPORATION | |
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By: | | /s/ CHRISTOPHER M. CRANE | |
Name: | | Christopher M. Crane | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ CHRISTOPHER M. CRANE | | President and Chief Executive Officer (Principal Executive Officer) and Director |
Christopher M. Crane | |
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/s/ JONATHAN W. THAYERJOSEPH NIGRO | | Senior Executive Vice President and Chief Financial Officer (Principal Financial Officer) |
Jonathan W. ThayerJoseph Nigro | |
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/s/ DUANE M. DESPARTEFABIAN E. SOUZA | | Senior Vice President and Corporate Controller (Principal Accounting Officer) |
Duane M. DesParteFabian E. Souza | |
This annual report has also been signed below by Thomas S. O'Neil,O'Neill, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
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| Anthony K. Anderson Ann C. Berzin Laurie Brlas Christopher M. Crane Yves C. de Balmann Nicholas DeBenedictis Nancy L. Gioia
Linda P. Jojo
| | Paul L. Joskow Robert J. Lawless Richard W. Mies John W. Rogers, Jr. Mayo A. Shattuck III Stephen D. Steinour |
John F. Young |
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By: | | /s/ THOMAS S. O'NEILL | | February 9, 20188, 2019 |
Name: | | Thomas S. O'Neill | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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EXELON GENERATION COMPANY, LLC | |
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By: | | /s/ KENNETH W. CORNEW | |
Name: | | Kenneth W. Cornew | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ KENNETH W. CORNEW | | President and Chief Executive Officer (Principal Executive Officer) |
Kenneth W. Cornew | |
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/s/ BRYAN P. WRIGHT | | Senior Vice President and Chief Financial Officer (Principal Financial Officer) |
Bryan P. Wright | |
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/s/ MATTHEW N. BAUER | | Vice President and Controller (Principal Accounting Officer) |
Matthew N. Bauer
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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COMMONWEALTH EDISON COMPANY | |
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By: | | /s/ ANNE R. PRAMAGGIOREJOSEPH DOMINGUEZ | |
Name: | | Anne R. PramaggioreJoseph Dominguez | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ ANNE R. PRAMAGGIOREJOSEPH DOMINGUEZ | | President and Chief Executive Officer (Principal Executive Officer) and Director |
Anne R. PramaggioreJoseph Dominguez | |
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/s/ JOSEPH R. TRPIK, JR.JEANNE M. JONES | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
Joseph R. Trpik, Jr.Jeanne M. Jones | |
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/s/ GERALD J. KOZEL | | Vice President and Controller (Principal Accounting Officer) |
Gerald J. Kozel | |
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/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Anne R. Pramaggiore,Joseph Dominguez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
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James W. Compton Christopher M. Crane A. Steven Crown Nicholas DeBenedictis
| | Peter V. Fazio, Jr. Michael H. Moskow Denis P. O'BrienAnne R. Pramaggiore
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By: | | /s/ ANNE R. PRAMAGGIOREJOSEPH DOMINGUEZ | | February 9, 20188, 2019 |
Name: | | Anne R. PramaggioreJoseph Dominguez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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PECO ENERGY COMPANY | |
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By: | | /s/ CRAIG L. ADAMSMICHAEL A. INNOCENZO | |
Name: | | Craig L. AdamsMichael A. Innocenzo | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ CRAIG L. ADAMSMICHAEL A. INNOCENZO | | President and Chief Executive Officer (Principal Executive Officer) and Director |
Craig L. AdamsMichael A. Innocenzo | |
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/s/ PHILLIP S. BARNETTROBERT J. STEFANI | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
Phillip S. BarnettRobert J. Stefani | |
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/s/ SCOTT A. BAILEY | | Vice President and Controller (Principal Accounting Officer) |
Scott A. Bailey | |
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/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Craig L. Adams,Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
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Christopher M. Crane | | Rosemarie B. GrecoJohn S. Grady |
M. Walter D’Alessio | | Charisse R. LillieRosemarie B. Greco |
Nicholas DeBenedictis | | Denis P. O'BrienCharisse R. Lillie |
Nelson A. Diaz | | |
| | Anne R. Pramaggiore |
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By: | | /s/ CRAIG L. ADAMSMICHAEL A. INNOCENZO | | February 9, 20188, 2019 |
Name: | | Craig L. AdamsMichael A. Innocenzo | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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BALTIMORE GAS AND ELECTRIC COMPANY | |
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By: | | /s/ CALVIN G. BUTLER, JR. | |
Name: | | Calvin G. Butler, Jr. | |
Title: | | Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ CALVIN G. BUTLER, JR. | | Chief Executive Officer (Principal Executive Officer) and Director |
Calvin G. Butler, Jr. | |
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/s/ DAVID M. VAHOS | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer) |
David M. Vahos | |
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/s/ ANDREW W. HOLMES | | Vice President and Controller (Principal Accounting Officer) |
Andrew W. Holmes | |
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/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | | |
This annual report has also been signed below by Calvin G. Butler, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:
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Ann C. Berzin | | Joseph Haskins, Jr. |
Christopher M. Crane | | Denis P. O'BrienAnne R. Pramaggiore |
Michael E. Cryor | | Michael D. Sullivan |
James R. Curtiss | | Maria Harris Tildon |
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By: | | /s/ CALVIN G. BUTLER, JR. | | February 9, 20188, 2019 |
Name: | | Calvin G. Butler, Jr. | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
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PEPCO HOLDINGS LLC | |
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By: | | /s/ DAVID M. VELAZQUEZ | |
Name: | | David M. Velazquez | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ DAVID M. VELAZQUEZ | | President and Chief Executive Officer (Principal Executive Officer) |
David M. Velazquez | |
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/s/ DONNA J. KINZELPHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
Donna J. KinzelPhillip S. Barnett | |
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/s/ ROBERT M. AIKEN | | Vice President and Controller (Principal Accounting Officer) |
Robert M. Aiken | |
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/s/ CHRISTOPHER M. CRANE | | Chairman and Director |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
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Christopher M. Crane | | Ernest Dianastasis |
Linda W. Cropp | | Debra P. DiLorenzo |
Michael E. Cryor | | Denis P. O'BrienAnne R. Pramaggiore |
|
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By: | | /s/ DAVID M. VELAZQUEZ | | February 9, 20188, 2019 |
Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
|
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POTOMAC ELECTRIC POWER COMPANY | |
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By: | | /s/ DAVID M. VELAZQUEZ | |
Name: | | David M. Velazquez | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
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Signature | | Title |
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/s/ DAVID M. VELAZQUEZ | | President and Chief Executive Officer (Principal Executive Officer) |
David M. Velazquez | |
| |
/s/ DONNA J. KINZELPHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
Donna J. KinzelPhillip S. Barnett | |
| |
/s/ ROBERT M. AIKEN | | Vice President and Controller (Principal Accounting Officer) |
Robert M. Aiken | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
| | |
J. Tyler Anthony | | Melissa A. Lavinson |
Phillip S. Barnett | | Kevin M. McGowan |
Christopher M. Crane | | Denis P. O'Brien |
Donna J. Kinzel | | Anne R. Pramaggiore |
|
| | | | |
By: | | /s/ DAVID M. VELAZQUEZ | | February 9, 20188, 2019 |
Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
|
| | | |
DELMARVA POWER & LIGHT COMPANY | |
| | |
By: | | /s/ DAVID M. VELAZQUEZ | |
Name: | | David M. Velazquez | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
|
| | |
Signature | | Title |
| |
/s/ DAVID M. VELAZQUEZ | | President and Chief Executive Officer (Principal Executive Officer) |
David M. Velazquez | |
| |
/s/ DONNA J. KINZELPHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
Donna J. KinzelPhillip S. Barnett | |
| |
/s/ ROBERT M. AIKEN | | Vice President and Controller (Principal Accounting Officer) |
Robert M. Aiken | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
|
| | |
Denis P. O'BrienAnne R. Pramaggiore | | |
|
| | | | |
By: | | /s/ DAVID M. VELAZQUEZ | | February 9, 20188, 2019 |
Name: | | David M. Velazquez | | |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 9th8th day of February, 2018.2019.
|
| | | |
ATLANTIC CITY ELECTRIC COMPANY | |
| | |
By: | | /s/ DAVID M. VELAZQUEZ | |
Name: | | David M. Velazquez | |
Title: | | President and Chief Executive Officer | |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the capacities indicated on the 9th8th day of February, 2018.2019.
|
| | |
Signature | | Title |
| |
/s/ DAVID M. VELAZQUEZ | | President and Chief Executive Officer (Principal Executive Officer) |
David M. Velazquez | |
| |
/s/ DONNA J. KINZELPHILLIP S. BARNETT | | Senior Vice President, Chief Financial Officer and Treasurer (Principal Financial Officer)
|
Donna J. KinzelPhillip S. Barnett | |
| |
/s/ ROBERT M. AIKEN | | Vice President and Controller (Principal Accounting Officer) |
Robert M. Aiken | |
| | |
/s/ CHRISTOPHER M. CRANE | | Chairman |
Christopher M. Crane | |