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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
| ☒ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the Fiscal Year Ended December 31, 2016
or
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
|
Commission File |
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number |
IRS Employer Identification Number | ||
| 1-16169 |
EXELON CORPORATION (a Pennsylvania
corporation) 10 South Dearborn Street |
23-2990190 | ||
| 333-85496 |
EXELON GENERATION COMPANY, LLC (a Pennsylvania limited
liability company) 300 Exelon Way |
23-3064219 | ||
| 1-1839 |
COMMONWEALTH EDISON COMPANY (an Illinois
corporation) 440 South LaSalle Street |
36-0938600 | ||
| 000-16844 |
PECO ENERGY COMPANY (a Pennsylvania
corporation) P.O. Box 8699 |
23-0970240 | ||
| 1-1910 |
BALTIMORE GAS AND ELECTRIC COMPANY (a Maryland
corporation) 2 Center Plaza |
52-0280210 | ||
| 001-31403 |
PEPCO HOLDINGS LLC (a Delaware limited liability
company) 701 Ninth Street, N.W. |
52-2297449 | ||
| 001-01072 |
POTOMAC ELECTRIC POWER COMPANY (a District of Columbia
and Virginia corporation) 701 Ninth Street, N.W. |
53-0127880 | ||
| 001-01405 |
DELMARVA POWER & LIGHT COMPANY (a Delaware and
Virginia corporation) 500 North Wakefield Drive |
51-0084283 | ||
| 001-03559 |
ATLANTIC CITY ELECTRIC COMPANY (a New Jersey
corporation) 500 North Wakefield Drive |
21-0398280 |
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Securities registered pursuant to Section 12(b) of the Act:
| 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 | |||
| BALTIMORE GAS AND ELECTRIC COMPANY: |
||||
| 6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and unconditionally guaranteed, by Baltimore Gas and Electric Company |
New York | |||
Securities registered pursuant to Section 12(g) of the Act:
| Title of Each Class |
| COMMONWEALTH EDISON COMPANY: |
| Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants |
| POTOMAC ELECTRIC POWER COMPANY: |
| Common Stock, $.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.
| Exelon Corporation |
Yes ☒ | No ☐ | ||
| Exelon Generation Company, LLC |
Yes ☒ | No ☐ | ||
| Commonwealth Edison Company |
Yes ☒ | No ☐ | ||
| PECO Energy Company |
Yes ☒ | No ☐ | ||
| Baltimore Gas and Electric Company |
Yes ☒ | No ☐ | ||
| Pepco Holdings LLC |
Yes ☒ | No ☐ | ||
| Potomac Electric Power Company |
Yes ☐ | No ☒ | ||
| Delmarva Power & Light Company |
Yes ☐ | No ☒ | ||
| Atlantic City Electric Company |
Yes ☐ | No ☒ |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| Exelon Corporation |
Yes ☐ | No ☒ | ||
| Exelon Generation Company, LLC |
Yes ☐ | No ☒ | ||
| Commonwealth Edison Company |
Yes ☐ | No ☒ | ||
| PECO Energy Company |
Yes ☐ | No ☒ | ||
| Baltimore Gas and Electric Company |
Yes ☐ | No ☒ | ||
| Pepco Holdings LLC |
Yes ☐ | No ☒ | ||
| Potomac Electric Power Company |
Yes ☐ | No ☒ | ||
| Delmarva Power & Light Company |
Yes ☐ | No ☒ | ||
| Atlantic City Electric Company |
Yes ☐ | No ☒ |
Indicate by check mark whether the registrants (1) have 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) have been subject to such filing requirements for the past 90 days. Yes ☒ 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 ☒ 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. ☒
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large Accelerated Filer |
Accelerated Filer |
Non-accelerated Filer |
Smaller Reporting Company |
|||||||
| Exelon Corporation |
☒ | |||||||||
| Exelon Generation Company, LLC |
☒ | |||||||||
| Commonwealth Edison Company |
☒ | |||||||||
| PECO Energy Company |
☒ | |||||||||
| Baltimore Gas and Electric Company |
☒ | |||||||||
| Pepco Holdings LLC |
☒ | |||||||||
| Potomac Electric Power Company |
☒ | |||||||||
| Delmarva Power & Light Company |
☒ | |||||||||
| Atlantic City Electric Company |
☒ | |||||||||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2016 was as follows:
| Exelon Corporation Common Stock, without par value |
$33,527,039,724 | |
| 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, 2017 was as follows:
| Exelon Corporation Common Stock, without par value |
926,589,614 | |
| Exelon Generation Company, LLC |
not applicable | |
| Commonwealth Edison Company Common Stock, $12.50 par value |
127,017,157 | |
| PECO Energy Company Common Stock, without par value |
170,478,507 | |
| Baltimore Gas and Electric Company, without par value |
1,000 | |
| Pepco Holdings LLC |
not applicable | |
| Potomac Electric Power Company Common Stock, $.01 par value |
100 | |
| Delmarva Power & Light Company Common Stock, $2.25 par value |
1,000 | |
| Atlantic City Electric Company Common Stock, $3.00 par value |
8,546,017 |
Documents Incorporated by Reference
Portions of the Exelon Proxy Statement for the 2017 Annual Meeting of
Shareholders and the Commonwealth Edison Company 2017 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.
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| ITEM 1B. |
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| ITEM 4. |
74 | |||||
| PART II |
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| ITEM 5. |
75 | |||||
| ITEM 6. |
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| ITEM 7. |
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS |
85 | ||||
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| ITEM 7A. |
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| ITEM 8. |
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| ITEM 9. |
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
579 | ||||
| ITEM 9A. |
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| PART III |
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| ITEM 10. |
581 | |||||
| ITEM 11. |
582 | |||||
| ITEM 12. |
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
583 | ||||
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| ITEM 13. |
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
584 | ||||
| ITEM 14. |
585 | |||||
| PART IV |
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| ITEM 15. |
586 | |||||
| ITEM 16. |
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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 | |
| Pepco Energy Services or PES |
Pepco Energy Services, Inc. and its subsidiaries | |
| PCI |
Potomac Capital Investment Corporation and its subsidiaries | |
| DPL |
Delmarva Power & Light Company | |
| ACE |
Atlantic City Electric Company | |
| BSC |
Exelon Business Services Company, LLC | |
| PHISCO |
PHI Service Company | |
| Exelon Corporate |
Exelon in its corporate capacity as a holding company | |
| PHI Corporate |
PHI in its corporate capacity as a holding company | |
| CENG |
Constellation Energy Nuclear Group, LLC | |
| Constellation |
Constellation Energy Group, Inc. | |
| Antelope Valley |
Antelope Valley Solar Ranch One | |
| Exelon Transmission Company |
Exelon Transmission Company, LLC | |
| Exelon Wind |
Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC | |
| Ventures |
Exelon Ventures Company, LLC | |
| EGTP |
ExGen Texas Power, LLC | |
| EGR |
ExGen Renewables I, LLC | |
| AmerGen |
AmerGen Energy Company, LLC | |
| RPG |
Renewable Power Generation | |
| SolGen |
SolGen, LLC | |
| BondCo |
RSB BondCo LLC | |
| PEC L.P. |
PECO Energy Capital, L.P. | |
| PECO Trust III |
PECO Capital Trust III | |
| PECO Trust IV |
PECO Energy Capital Trust IV | |
| PETT |
PECO Energy Transition Trust | |
| ACE Funding or ATF |
Atlantic City Electric Transition Funding LLC | |
| 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 and ACE, collectively | |
| ConEdison Solutions |
The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a subsidiary of Consolidated Edison, Inc | |
| UII |
Unicom Investments, Inc. | |
| Other Terms and Abbreviations | ||
| 1998 restructuring settlement |
PECO’s 1998 settlement of its restructuring case mandated by the Competition Act | |
| Act 11 |
Pennsylvania Act 11 of 2012 | |
| Act 129 |
Pennsylvania Act 129 of 2008 | |
| AEC |
Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified alternative energy source | |
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| Other Terms and Abbreviations | ||
| AEPS |
Pennsylvania Alternative Energy Portfolio Standards | |
| AEPS Act |
Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended | |
| AESO |
Alberta Electric Systems Operator | |
| AFUDC |
Allowance for Funds Used During Construction | |
| ALJ |
Administrative Law Judge | |
| AMI |
Advanced Metering Infrastructure | |
| AMP |
Advanced Metering Program | |
| AOCI |
Accumulated Other Comprehensive Income | |
| ARC |
Asset Retirement Cost | |
| ARO |
Asset Retirement Obligation | |
| ARP |
Title IV Acid Rain Program | |
| ARRA of 2009 |
American Recovery and Reinvestment Act of 2009 | |
| ASC |
Accounting Standards Codification | |
| BGS |
Basic Generation Service | |
| Block contracts |
Forward Purchase Energy Block Contracts | |
| CAIR |
Clean Air Interstate Rule | |
| CAISO |
California ISO | |
| CAMR |
Federal Clean Air Mercury Rule | |
| CERCLA |
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended | |
| CES |
Clean Energy Standard | |
| CFL |
Compact Fluorescent Light | |
| Clean Air Act |
Clean Air Act of 1963, as amended | |
| Clean Water Act |
Federal Water Pollution Control Amendments of 1972, as amended | |
| Competition Act |
Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996 | |
| Conectiv |
Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE | |
| Conectiv Energy |
Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine in July 2010 | |
| Contract EDCs |
Pepco, DPL and BGE, the Maryland utilities required by the MDPSC to enter into a contract for new generation | |
| CPI |
Consumer Price Index | |
| CPUC |
California Public Utilities Commission | |
| CSAPR |
Cross-State Air Pollution Rule | |
| CTA |
Consolidated tax adjustment | |
| CTC |
Competitive Transition Charge | |
| D.C. Circuit Court |
United States Court of Appeals for the District of Columbia Circuit | |
| DCPSC |
District of Columbia Public Service Commission | |
| DC PLUG |
District of Columbia Power Line Undergrounding | |
| Default Electricity Supply |
The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers who do not elect to purchase electricity from a competitive supplier, and which, depending on the jurisdiction, is also known as Standard Offer Service or BGS | |
| Default Electricity Supply Revenue |
Revenue primarily from Default Electricity Supply | |
| DOE |
United States Department of Energy | |
| DOJ |
United States Department of Justice | |
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| Other Terms and Abbreviations | ||
| DPSC |
Delaware Public Service Commission | |
| DRP |
Direct Stock Purchase and Dividend Reinvestment Plan | |
| DSP |
Default Service Provider | |
| DSP Program |
Default Service Provider Program | |
| EDCs |
Electric distribution companies | |
| EDF |
Electricite de France SA and its subsidiaries | |
| EE&C |
Energy Efficiency and Conservation/Demand Response | |
| EGS |
Electric Generation Supplier | |
| 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 | |
| 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 | |
| FTC |
Federal Trade Commission | |
| GAAP |
Generally Accepted Accounting Principles in the United States | |
| GCR |
Gas Cost Rate | |
| GHG |
Greenhouse Gas | |
| GRT |
Gross Receipts Tax | |
| GSA |
Generation Supply Adjustment | |
| GWh |
Gigawatt hour | |
| HAP |
Hazardous air pollutants | |
| Health Care Reform Acts |
Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of 2010 | |
| HSR Act |
The Hart-Scott-Rodino Antitrust Improvements Act of 1976 | |
| IBEW |
International Brotherhood of Electrical Workers | |
| ICC |
Illinois Commerce Commission | |
| ICE |
Intercontinental Exchange | |
| Illinois Act |
Illinois Electric Service Customer Choice and Rate Relief Law of 1997 | |
| Illinois EPA |
Illinois Environmental Protection Agency | |
| Illinois Settlement Legislation |
Legislation enacted in 2007 affecting electric utilities in Illinois | |
| Integrys |
Integrys Energy Services, Inc. | |
| IPA |
Illinois Power Agency | |
| IRC |
Internal Revenue Code | |
| IRS |
Internal Revenue Service | |
| ISO |
Independent System Operator | |
| ISO-NE |
ISO New England Inc. | |
| ISO-NY |
ISO New York | |
| kV |
Kilovolt | |
| kW |
Kilowatt | |
| kWh |
Kilowatt-hour | |
| LIBOR |
London Interbank Offered Rate | |
| LILO |
Lease-In, Lease-Out | |
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| Other Terms and Abbreviations | ||
| LLRW |
Low-Level Radioactive Waste | |
| LT Plan |
Long-term renewable resources procurement plan | |
| 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 | |
| MRV |
Market-Related Value | |
| MW |
Megawatt | |
| MWh |
Megawatt hour | |
| NAAQS |
National Ambient Air Quality Standards | |
| n.m. |
not meaningful | |
| NAV |
Net Asset Value | |
| NDT |
Nuclear Decommissioning Trust | |
| NEIL |
Nuclear Electric Insurance Limited | |
| NERC |
North American Electric Reliability Corporation | |
| NGS |
Natural Gas Supplier | |
| NJBPU |
New Jersey Board of Public Utilities | |
| NJDEP |
New Jersey Department of Environmental Protection | |
| Non-Regulatory Agreements Units |
Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting | |
| NOSA |
Nuclear Operating Services Agreement | |
| NOV |
Notice of Violation | |
| NPDES |
National Pollutant Discharge Elimination System | |
| NRC |
Nuclear Regulatory Commission | |
| NSPS |
New Source Performance Standards | |
| NUGs |
Non-utility generators | |
| NWPA |
Nuclear Waste Policy Act of 1982 | |
| NYMEX |
New York Mercantile Exchange | |
| OCI |
Other Comprehensive Income | |
| OIESO |
Ontario Independent Electricity System Operator | |
| OPC |
Office of People’s Counsel | |
| OPEB |
Other Postretirement Employee Benefits | |
| PA DEP |
Pennsylvania Department of Environmental Protection | |
| PAPUC |
Pennsylvania Public Utility Commission | |
| PGC |
Purchased Gas Cost Clause | |
| PHI Retirement Plan |
PHI’s noncontributory retirement plan | |
| 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 | |
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| Other Terms and Abbreviations | ||
| PRP |
Potentially Responsible Parties | |
| PSEG |
Public Service Enterprise Group Incorporated | |
| PURTA |
Pennsylvania Public Realty Tax Act | |
| PV |
Photovoltaic | |
| RCRA |
Resource Conservation and Recovery Act of 1976, as amended | |
| REC |
Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source | |
| Regulatory Agreement Units |
Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting | |
| RES |
Retail Electric Suppliers | |
| RFP |
Request for Proposal | |
| Rider |
Reconcilable Surcharge Recovery Mechanism | |
| RGGI |
Regional Greenhouse Gas Initiative | |
| RMC |
Risk Management Committee | |
| ROE |
Return on equity | |
| RPM |
PJM Reliability Pricing Model | |
| RPS |
Renewable Energy Portfolio Standards | |
| RSSA |
Reliability Support Services Agreement | |
| RTEP |
Regional Transmission Expansion Plan | |
| RTO |
Regional Transmission Organization | |
| S&P |
Standard & Poor’s Ratings Services | |
| SEC |
United States Securities and Exchange Commission | |
| Senate Bill 1 |
Maryland Senate Bill 1 | |
| SERC |
SERC Reliability Corporation (formerly Southeast Electric Reliability Council) | |
| SERP |
Supplemental Employee Retirement Plan | |
| SGIG |
Smart Grid Investment Grant from DOE | |
| SGIP |
Smart Grid Initiative Program | |
| SILO |
Sale-In, Lease-Out | |
| SMPIP |
Smart Meter Procurement and Installation Plan | |
| SNF |
Spent Nuclear Fuel | |
| SOCAs |
Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New Jersey law enacted to promote the construction of qualified electric generation facilities in New Jersey | |
| SOS |
Standard Offer Service | |
| SPP |
Southwest Power Pool | |
| Tax Relief Act of 2010 |
Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
| 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 | |
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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.
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 a Registrants include those factors discussed herein, including those factors discussed with respect to such Registrant 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 24; 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 read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the SEC at www.sec.gov and the Registrants’ websites at www.exeloncorp.com. Information contained on the Registrants’ websites shall not be deemed incorporated into, or to be a part of, this Report.
PART I
| ITEM 1. | BUSINESS |
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, and its telephone number is 800-483-3220.
Generation
Generation’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.
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Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate restructuring, effective January 1, 2001, in which Exelon separated its generation and other competitive businesses from its regulated energy delivery businesses at ComEd and PECO.
Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is 610-765-5959.
ComEd
ComEd’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in northern Illinois, including the City of Chicago.
ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation named Commonwealth Edison Company, which was incorporated in 1907. ComEd’s principal executive offices are located at 440 South LaSalle Street, Chicago, Illinois 60605, and its telephone number is 312-394-4321.
PECO
PECO’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia.
PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia, Pennsylvania 19103, and its telephone number is 215-841-4000.
BGE
BGE’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services to retail customers in central Maryland, including the City of Baltimore.
BGE was incorporated in Maryland in 1906. BGE’s principal executive offices are located at 110 West Fayette Street, Baltimore, Maryland 21201, and its telephone number is 410-234-5000.
PHI
PHI is a utility services holding company engaged, through its reportable segments Pepco, DPL and ACE, in the energy delivery businesses discussed below. On March 23, 2016, Pepco Holdings, Inc., converted from a Delaware corporation to a Delaware limited liability company, Pepco Holdings LLC. PHI’s principal executive offices are located at 701 Ninth Street, N.W., Washington, D.C. 20068, and its telephone number is 202-872-2000.
Pepco
Pepco’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in the District of Columbia and major portions of Montgomery County and Prince George’s County in Maryland.
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Pepco was incorporated in the District of Columbia in 1896 and Virginia in 1949. Pepco’s principal executive offices are located at 701 Ninth Street, N.W., Washington, D.C. 20068, and its telephone number is 202-872-2000.
DPL
DPL’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in portions of Delaware and Maryland, as well as the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services to retail customers in portions of New Castle County in Delaware.
DPL was incorporated in Delaware in 1909 and Virginia in 1979. DPL’s principal executive offices are located at 500 North Wakefield Drive, Newark, Delaware 19702, and its telephone number is 202-872-2000.
ACE
ACE’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and distribution services to retail customers in portions of southern New Jersey.
ACE was incorporated in New Jersey in 1924. ACE’s principal executive offices are located at 500 North Wakefield Drive, Newark, Delaware 19702, and its telephone number is 202-872-2000.
Business Services
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.
Operating Segments
See Note 26—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). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon’s interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the
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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 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI transaction.
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 also 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. Additionally, 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 mandatory reliability standards promulgated by the NERC, with the approval of FERC.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. PJM, MISO, ISO-NE and SPP, have been approved by FERC as RTOs, and CAISO and ISO-NY have been approved 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.
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Constellation Energy Nuclear Group, Inc.
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 and Nine Mile Point. CENG’s ownership share in the total capacity of these units is 4,007 MW. See ITEM 2. PROPERTIES for additional information on these sites.
Generation and EDF also 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. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months.
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 of 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. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for further information regarding the integration transaction.
Acquisitions
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.
Merger with Constellation Energy Group, Inc. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.
Dispositions
Upstream Disposition. On June 16, 2016, Generation initiated the sales process of its Upstream business. See Note 14—Debt and Credit Agreements for more 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 on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.
Asset Divestitures. During 2014 and 2015, 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.
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Maryland Clean Coal Stations. On November 30, 2012, a subsidiary of Generation sold the Brandon Shores generating station and H.A. Wagner generating station in Anne Arundel County, Maryland, and the C.P. Crane generating station in Baltimore County, Maryland to Raven Power Holdings LLC, a subsidiary of Riverstone Holdings LLC to comply with certain of the regulatory approvals required by the merger with Constellation Energy Group, Inc. for net proceeds of approximately $371 million, which resulted in a pre-tax impairment charge of $272 million.
See Note 4—Mergers, Acquisitions, and Dispositions and Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Generating Resources
At December 31, 2016, the generating resources of Generation consisted of the following:
| Type of Capacity |
MW | |||
| Owned generation assets (a)(b) |
||||
| Nuclear |
19,457 | |||
| Fossil (primarily natural gas and oil) |
9,548 | |||
| Renewable (c) |
3,715 | |||
|
|
|
|||
| Owned generation assets |
32,720 | |||
| Long-term power purchase contracts (d) |
6,879 | |||
|
|
|
|||
| Total generating resources |
39,599 | |||
|
|
|
|||
| (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, and solar generating assets. |
| (d) | Electric supply procured under site specific agreements. |
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 customer-facing activities are conducted and where Generation’s generating resources are located.
| • | 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 36% 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 (excluding 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 Kentucky (approximately 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 7% of capacity). |
| • | New York represents the operations within ISO-NY, which covers the state of New York in its entirety (approximately 3% of capacity). |
| • | ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas (approximately 11% of capacity). |
| • | Other Power Regions is an aggregate of regions not considered individually significant (approximately 6% of capacity). |
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See Note 26—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.
Nuclear Facilities
Generation has ownership interests in fourteen nuclear generating stations currently in service, consisting of 24 units with an aggregate of 19,457 MW of capacity. Generation wholly owns all of its nuclear generating stations, except for Quad Cities Generating Station (75% ownership), Peach Bottom Generating Station (50% ownership), and Salem Generating Station (Salem) (42.59% ownership), which are consolidated on Exelon’s and Generation’s financial statements relative to its proportionate ownership interest in each unit. In addition, Generation owns a 50.01% interest, collectively, in the CENG generating stations (Calvert Cliffs, Nine Mile Point [excluding LIPA’s 18% ownership interest in Nine Mile Point Unit 2] and R.E. Ginna) which are 100% consolidated on Exelon and Generation’s financial statements as of April 1, 2014. See Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for additional information. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the impact of the Future Energy Jobs Bill and New York CES on certain nuclear plants.
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 2016, 2015 and 2014 electric supply (in GWh) generated from the nuclear generating facilities was 67%, 68% and 67%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric and renewable generation and electric supply purchased for resale. The majority of this output was dispatched to support Generation’s wholesale and retail power marketing activities. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for further discussion of Generation’s electric supply sources.
On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York. Closing of the transaction is currently anticipated to occur in the first half of 2017 and requires regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act (which has been completed) and other customary closing conditions. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail on the proposed acquisition of the FitzPatrick nuclear generating station.
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 2016, 2015 and 2014, the nuclear generating facilities operated by Generation achieved capacity factors of 94.6%, 93.7% and 94.3%, respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG as of April 1, 2014. 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
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marketing and trading 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 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. As of January 30, 2017, the NRC categorized Ginna in the Regulatory Response Column, which is the second highest of five performance bands. All other units operated by Generation are categorized in the Licensee Response Column, which is the highest performance band. 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 for nuclear generating facilities and/or increased operating costs of nuclear generating units.
For information on the NRC actions related to the Japan Earthquake and Tsunami and the industry’s response, see ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Executive Overview.
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 December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019.
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The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:
| Station |
Unit | In-Service Date (a) |
Current License Expiration |
|||||||||
| Braidwood |
1 | 1988 | 2046 | |||||||||
| 2 | 1988 | 2047 | ||||||||||
| Byron |
1 | 1985 | 2044 | |||||||||
| 2 | 1987 | 2046 | ||||||||||
| Calvert Cliffs |
1 | 1975 | 2034 | |||||||||
| 2 | 1977 | 2036 | ||||||||||
| Clinton (b) |
1 | 1987 | 2026 | |||||||||
| Dresden |
2 | 1970 | 2029 | |||||||||
| 3 | 1971 | 2031 | ||||||||||
| LaSalle |
1 | 1984 | 2042 | |||||||||
| 2 | 1984 | 2043 | ||||||||||
| Limerick |
1 | 1986 | 2044 | |||||||||
| 2 | 1990 | 2049 | ||||||||||
| Nine Mile Point |
1 | 1969 | 2029 | |||||||||
| 2 | 1988 | 2046 | ||||||||||
| Oyster Creek (c) |
1 | 1969 | 2029 | |||||||||
| Peach Bottom (d) |
2 | 1974 | 2033 | |||||||||
| 3 | 1974 | 2034 | ||||||||||
| Quad Cities |
1 | 1973 | 2032 | |||||||||
| 2 | 1973 | 2032 | ||||||||||
| R.E. Ginna |
1 | 1970 | 2029 | |||||||||
| Salem |
1 | 1977 | 2036 | |||||||||
| 2 | 1981 | 2040 | ||||||||||
| Three Mile Island |
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) | In December 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. In 2016, Exelon notified the NRC that it will cease operations at Oyster Creek on November 30, 2019. |
| (d) | On June 7, 2016, Generation announced that it will submit a second 20 year license renewal application to NRC for Peach Bottom Units 2 and 3 in 2018. |
The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review. The NRC review process takes approximately two years from the docketing of an 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 and Clinton. Oyster Creek depreciation provisions are based on the 2019 expected shutdown date. Clinton depreciation provisions are based on 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional detail on the new Illinois legislation and Note 9—Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional detail on the reversal of the decision to early retire Clinton.
In August 2012, Generation entered into an operating services agreement with the Omaha Public Power District (OPPD) to provide operational and managerial support services for the Fort Calhoun Station and a licensing agreement for use of the Exelon Nuclear Management Model. On
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December 16, 2016, Generation was notified by OPPD of the termination of the operating services agreement for Fort Calhoun Station effective June 14, 2017. OPPD has the option to continue to use the Exelon Nuclear Management Model for payment of a fee.
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, 2016, Generation had approximately 77,900 SNF assemblies (19,200 tons) stored on site in SNF pools or dry cask storage (this 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 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station Decommissioning). All currently operating Generation-owned nuclear sites have on-site dry cask storage, except for Three Mile Island, where such storage is projected to be in operation in 2023. 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 24—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. 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 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 cost impacts and on-site storage.
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
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reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for details.
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.
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. 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 3—Regulatory Matters, Note 12—Fair Value of Financial Assets and Liabilities and Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations. The ultimate decommissioning obligation will be funded by the NDTs. The NDTs are recorded on Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 2016 at fair value of approximately $11.1 billion and have an estimated targeted annual pre-tax return of 5.3% to 5.9%.
Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement (ASA) with EnergySolutions, Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, LLC (ZionSolutions) under which ZionSolutions assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998.
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 shall be deferred until such milestones are met. See Note 16—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, 2016, Generation had ownership interests in 13,263 MW of capacity in generating facilities currently in service, consisting of 9,522 MW of natural gas and oil, 3,715 MW of renewables (wind, hydroelectric, and solar) and 26 MW of waste coal. Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) jointly owned facilities that include Wyman; (2) certain wind project entities with minority interest owners; and (3) an ownership interest in the Albany Green Energy, LLC project entity, 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
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and Wyman, which are operated by third parties. In 2016, 2015 and 2014, electric supply (in GWh) generated from owned fossil and renewable generating facilities was 10%, 8% and 13%, 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. On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (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. Based on the FERC procedural schedule, the FERC licensing process was not completed prior to the expiration of Conowingo’s license on September 1, 2014. FERC is required to issue an annual license for the facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not issue a new license prior to the expiration of annual license, the annual license will renew automatically. The stations are currently being depreciated over their estimated useful lives, which includes actual and anticipated license renewal periods. Refer to Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Insurance. Generation maintains business interruption insurance for its renewable and fossil projects, and delay in start-up insurance for its renewable and fossil projects currently under construction. Generation does not purchase business interruption insurance for its wholly owned fossil and hydroelectric operations, unless required by financing agreements; see Note 14—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.
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Long-Term Power Purchase Contracts
In addition to energy produced by owned generation assets, Generation sources electricity and other related output from plants it does not own under long-term contracts. The following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration, by region, in effect as of December 31, 2016:
| Region |
Number of Agreements |
Expiration Dates |
Capacity (MW) | |||||||
| Mid-Atlantic |
16 | 2017 - 2032 | 800 | |||||||
| Midwest |
6 | 2017 - 2026 | 1,236 | |||||||
| New England |
8 | 2017 | 650 | |||||||
| ERCOT |
5 | 2020 - 2031 | 1,501 | |||||||
| Other Power Regions |
11 | 2017 - 2030 | 2,692 | |||||||
|
|
|
|
|
|||||||
| Total |
46 | 6,879 | ||||||||
|
|
|
|
|
|||||||
| 2017 | 2018 | 2019 | 2020 | 2021 | ||||||||||||||||
| Capacity Expiring (MW) |
1,790 | 101 | 644 | 980 | 815 | |||||||||||||||
Fuel
The following table shows sources of electric supply in GWh for 2016 and 2015:
| Source of Electric Supply | ||||||||
| 2016 | 2015 | |||||||
| Nuclear (a) |
176,799 | 175,474 | ||||||
| Purchases—non-trading portfolio |
59,987 | 63,637 | ||||||
| Fossil (primarily natural gas and oil) |
19,830 | 14,936 | ||||||
| Renewable (b) |
6,324 | 5,982 | ||||||
|
|
|
|
|
|||||
| Total supply |
262,940 | 260,029 | ||||||
|
|
|
|
|
|||||
| (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 2016 and 2015 includes physical volumes of 33,444 GWh and 33,415 GWh, respectively, for CENG. |
| (b) | Includes wind, hydroelectric, and solar 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 uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2018. Generation’s contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2017. All of Generation’s enrichment requirements have been contracted through 2020. Contracts for fuel fabrication have been obtained through 2022. Generation 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
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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. Generation also hedges forward price risk, 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 13—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 the physical delivery and marketing of power obtained through its generation capacity and through long-term, intermediate-term and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term PPAs. PPAs, including tolling agreements, are commitments related to power generation of specific generation plants and/or are dispatchable in nature similar to asset ownership depending on the type of underlying asset. Generation secures contracted generation as part of its overall strategic plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to both wholesale and retail customers and assisting customers to meet renewable portfolio standards. 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. Generation’s customer facing operations combine a unified sales force with a customer-centric model that leverages technology to broaden the range of products and solutions offered, which Generation believes promotes stronger customer relationships. This model focuses on efficiency and cost reduction, which provides a platform that is scalable and able to capitalize on opportunities for future growth.
Generation may purchase more than the energy demanded by its customers. Generation then sells this open position, along with capacity not used to meet customer demand, in the wholesale electricity markets. Where necessary, Generation also purchases transmission service to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs in markets without an organized RTO. Generation also incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet summer loads at levels representative of warmer-than-normal weather conditions.
Price 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 also enters into transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2017 and beyond for portions of its electricity portfolio that are unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in subsequent years. As of December 31, 2016, the percentage of expected generation hedged for the major reportable segments was 91%-94%, 56%-59% and 28%-31% for 2017, 2018, and 2019, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generating facilities based upon a simulated dispatch model that
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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, which routinely change in the market. The corporate 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, including volume, stop-loss and value-at-risk limits, to manage exposure to market risk. 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 in nuclear fuel and energy generation assets and in other internal infrastructure projects. Generation’s estimated capital expenditures for 2017 are as follows:
| (in millions) |
||||
| Nuclear fuel (a) |
$ | 925 | ||
| Growth |
600 | |||
| Production plant |
1,125 | |||
|
|
|
|||
| Total |
$ | 2,650 | ||
|
|
|
|||
| (a) | Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant. |
ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services to retail customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the ICC related to distribution rates and service, the issuance of securities and certain other aspects of ComEd’s business. ComEd is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business. Specific operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEd is subject to NERC mandatory reliability standards.
ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights have stated expiration dates ranging from 2017 to 2066. ComEd anticipates working with the appropriate governmental bodies to extend or replace the franchise agreements prior to expiration.
PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of natural gas and the provision of gas distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO is a public utility under the Pennsylvania Public
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Utility Code subject to regulation by the PAPUC related to electric and gas distribution rates and service, the issuances of certain securities and certain other aspects of PECO’s business. PECO is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation related to pipeline safety and other areas of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, PECO is also subject to NERC mandatory reliability standards.
PECO has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities or territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the PAPUC and/or “grandfathered rights,” with all of such rights generally unlimited as to time and generally exclusive from competition from other electric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of another natural gas utility; however, PECO does not consider those situations as posing a material competitive or financial threat.
BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of natural gas and the provision of gas distribution services to retail customers in central Maryland, including the City of Baltimore. BGE is a public utility under the Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC related to electric and gas distribution rates and service, the issuances of certain securities and certain other aspects of BGE’s business. BGE is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of BGE’s business and by the U.S. Department of Transportation related to pipeline safety and other areas of gas operations. Specific operations of BGE are subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, BGE is also subject to NERC mandatory reliability standards.
BGE has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities and territories in which it now supplies such services. With respect to electric distribution service, BGE’s authorizations consist of charter rights, a state-wide franchise grant and a franchise grant from the City of Baltimore. The franchise rights are nonexclusive and are perpetual. Pursuant to statute, public service companies in Maryland may exercise a franchise to the extent authorized by the MDPSC. The service territory for BGE, as well as for other electric utilities in the state, was precisely delineated in 1966 by the MDPSC and has been modified in minor ways over the years. With respect to natural gas distribution service, BGE’s authorizations consist of charter rights, a perpetual state-wide franchise grant and franchises granted by all the municipalities and/or governmental bodies in which BGE now supplies services. The franchise grants are not exclusive; some are perpetual and some are for a limited duration, which BGE anticipates being able to extend or replace prior to expiration.
PHI was incorporated in Delaware in 2001. Through its reportable segments Pepco, DPL and ACE, PHI is engaged primarily in the transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas. On March 23, 2016, Pepco Holdings, Inc., converted from a Delaware corporation to a Delaware limited liability company, Pepco Holdings LLC. PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries.
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Pepco is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco is a public utility under the Code of the District of Columbia and subject to regulation by the DCPSC related to distribution rates and service, the issuance of securities and certain other aspects of Pepco’s business in the District of Columbia. Pepco is also an electric company under the Maryland Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC related to distribution rates and service, the issuance of securities and certain other aspects of Pepco’s business in Maryland. Pepco is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of Pepco’s business. Additionally, Pepco is subject to NERC mandatory reliability standards.
Pepco’s right to occupy public space for utility purposes is by permit from the District of Columbia and the federal government. Pepco is the only public utility that distributes electricity for sale to the public in the District of Columbia. In Maryland, Pepco operates pursuant to state-wide franchises granted by Maryland’s General Assembly that are unlimited in duration. Pursuant to statute, public service companies in Maryland may exercise a franchise to the extent authorized by the MDPSC. The service territories for Pepco, as well as for other electric utilities in the state, were precisely delineated in 1966 by the MDPSC and have been modified in minor ways over the years.
DPL is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services to retail customers in portions of Maryland and Delaware, as well as the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services to retail customers in New Castle County, Delaware. DPL is a public utility under the Delaware Code and subject to regulation by the DPSC related to electric and gas distribution rates and service, the issuance of certain securities and certain other aspects of DPL’s business in Delaware. In Maryland, DPL is an electric company under the Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC related to electric rates and service, the issuances of certain securities and certain other aspects of DPL’s business in Maryland. DPL is a public utility under the Federal Power Act and is subject to regulation by FERC related to transmission rates and certain other aspects of DPL’s business and by the U.S. Department of Transportation related to pipeline safety and other areas of gas operations. Additionally, DPL is also subject to NERC mandatory reliability standards.
DPL has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities and territories in which it now supplies such services. In Maryland, DPL operates pursuant to state-wide franchises that are substantially similar in nature to those described above with respect to Pepco’s Maryland operations. DPL’s exclusive and continuing authority to distribute electricity and natural gas in its non-municipal service territories in Delaware is derived from legislation, through which the DPSC has established exclusive service territories. With respect to municipalities that it serves, DPL provides service under various franchises granted to DPL and predecessor companies, which franchises are generally either unlimited as to time or renew automatically.
ACE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission services to retail customers in portions of southern New
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Jersey. ACE is a public utility under the New Jersey Public Utilities Act subject to regulation by the NJBPU related to distribution rates and service, the issuance of securities and certain other aspects of ACE’s business. ACE is a public utility under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ACE’s business. Additionally, ACE is subject to NERC mandatory reliability standards.
ACE’s franchises are sufficient to permit it to engage in the business it now conducts. ACE operates under non-exclusive franchises that have been granted by the NJBPU and under certain non-exclusive consents from municipalities in which ACE provides service. While most of the municipal consents were granted in perpetuity, two of the municipal consents require renewal on a periodic basis in accordance with their terms with respect to ACE’s continued right to erect and maintain wires and poles in, upon, over and under the public streets, streets and alleys, and are subject to the ultimate review and approval of the NJBPU. All of the franchises and consents are currently in full force and effect.
ComEd, PECO, BGE, Pepco, DPL and ACE
Service Territories. The following table presents the size of retail service territories, populations of each retail service territory and the number of retail customers within each retail service territory for the Utility Registrants as of December 31, 2016:
| Retail Service Territories (in square miles) |
Retail Service Territory Population (in millions) |
Number of Retail Customers (in millions) |
||||||||||||||||||||||||||||||||||
| 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 | ||||||||||||||||||||||||||
| PECO |
2,100 | 1,900 | 1,900 | 4.6 | (b) | 4.0 | 3.1 | 2.1 | 1.6 | 0.5 | ||||||||||||||||||||||||||
| BGE |
2,300 | 2,300 | 800 | 3.0 | (c) | 3.0 | 2.9 | 1.3 | 1.3 | 0.7 | ||||||||||||||||||||||||||
| Pepco |
640 | 640 | n/a | 2.4 | (d) | 2.4 | n/a | 0.9 | 0.9 | n/a | ||||||||||||||||||||||||||
| DPL |
5,675 | 5,400 | 275 | 2.0 | (e) | 1.4 | 0.6 | 0.6 | 0.5 | 0.1 | ||||||||||||||||||||||||||
| ACE |
2,800 | 2,800 | n/a | 1.1 | (f) | 1.1 | n/a | 0.5 | 0.5 | 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. |
Peak Deliveries. The Utility Registrants electric sales and peak load 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 sales are generally higher during the winter months when cold temperatures create demand for winter heating.
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The following table summarizes historic peak deliveries for the Utility Registrants for electric and gas deliveries during peak demand months through December 31, 2016:
| Electric Peak Deliveries (in GW) |
Natural Gas Peak Deliveries (in mmcfs) |
|||||||||||||||||||||||
| Summer peak date |
Summer deliveries |
Winter peak date |
Winter deliveries |
Winter peak date |
Winter deliveries |
|||||||||||||||||||
| ComEd |
7/20/2011 | 23.75 | 1/6/2014 | 16.51 | n/a | n/a | ||||||||||||||||||
| PECO |
7/22/2011 | 8.98 | 1/7/2014 | 7.17 | 2/15/2015 | 777 | ||||||||||||||||||
| BGE |
7/21/2011 | 7.23 | 2/20/2015 | 6.71 | 2/19/2015 | 777 | ||||||||||||||||||
| Pepco |
7/22/2011 | 7.02 | 2/20/2015 | 6.07 | n/a | n/a | ||||||||||||||||||
| DPL |
7/22/2011 | 4.14 | 2/20/2015 | 4.11 | 2/15/2015 | 186 | ||||||||||||||||||
| ACE |
7/22/2011 | 2.96 | 1/7/2014 | 1.8 | n/a | n/a | ||||||||||||||||||
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, pursuant to EIMA. 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 those customers that choose a competitive electric generation or natural gas supplier, the Utility Registrants may act as the billing agent but do not record revenues or purchased power and fuel expense related to the electricity and/or natural gas. For those customers that choose one of the Utility Registrants as their electric generation or natural gas supplier, the Utility Registrants are permitted to recover electric and natural gas procurement costs from retail customers. Therefore, fluctuations in electric and natural gas procurement costs have no impact on electric and natural gas revenues net of purchased power and fuel expense.
The following table outlines the state regulatory agencies and default service obligations for each of the Utility Registrants:
| Regulatory Agency |
Default Service |
Default Service | ||||
| ComEd |
ICC |
POLR |
n/a | |||
| PECO |
PAPUC |
DSP |
PGC | |||
| BGE |
MDPSC |
SOS |
MBR | |||
| Pepco |
DCPSC/MDPSC |
SOS |
n/a | |||
| DPL |
DPSC/MDPSC |
SOS |
n/a | |||
| ACE |
NJBPU |
BGS |
n/a |
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Retail customers participating in customer choice programs, and retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of GWh and mmcf sales, respectively) for the Utility Registrants consisted of the following at December 31, 2016, 2015 and 2014:
| December 31, 2016 | ||||||||||||||||||||||||
| Number of retail customers in customer choice programs |
% of total retail customers | Customer choice program deliveries as a % of retail sales (for the year ended) |
||||||||||||||||||||||
| Electric | Natural gas | Electric | Natural gas | Electric | Natural gas | |||||||||||||||||||
| ComEd |
1,502,900 | n/a | 38 | % | n/a | 72 | % | n/a | ||||||||||||||||
| PECO |
587,200 | 81,300 | 36 | % | 16 | % | 70 | % | 26 | % | ||||||||||||||
| BGE |
337,000 | 151,000 | 27 | % | 23 | % | 59 | % | 57 | % | ||||||||||||||
| Pepco |
176,372 | n/a | 21 | % | n/a | 65 | % | n/a | ||||||||||||||||
| DPL |
78,994 | 156 | 15 | % | 0.1 | % | 51 | % | 28 | % | ||||||||||||||
| ACE |
94,562 | n/a | 17 | % | n/a | 47 | % | n/a | ||||||||||||||||
| December 31, 2015 | ||||||||||||||||||||||||
| Number of retail customers in customer choice programs |
% of total retail customers | Customer choice program deliveries as a % of retail sales (for the year ended) |
||||||||||||||||||||||
| Electric | Natural gas | Electric | Natural gas | Electric | Natural gas | |||||||||||||||||||
| ComEd (a) |
1,655,400 | n/a | 42 | % | n/a | 76 | % | n/a | ||||||||||||||||
| PECO |
563,400 | 81,100 | 35 | % | 16 | % | 70 | % | 25 | % | ||||||||||||||
| BGE |
343,000 | 154,000 | 27 | % | 23 | % | 61 | % | 56 | % | ||||||||||||||
| Pepco |
173,222 | n/a | 21 | % | n/a | 65 | % | n/a | ||||||||||||||||
| DPL |
77,603 | 159 | 15 | % | 0.1 | % | 51 | % | 31 | % | ||||||||||||||
| ACE |
78,299 | n/a | 14 | % | n/a | 45 | % | n/a | ||||||||||||||||
| December 31, 2014 | ||||||||||||||||||||||||
| Number of retail customers in customer choice programs |
% of total retail customers | Customer choice program deliveries as a % of retail sales (for the year ended) |
||||||||||||||||||||||
| Electric | Natural gas | Electric | Natural gas | Electric | Natural gas | |||||||||||||||||||
| ComEd |
2,426,900 | n/a | 63 | % | n/a | 80 | % | n/a | ||||||||||||||||
| PECO |
546,900 | 78,400 | 34 | % | 16 | % | 70 | % | 22 | % | ||||||||||||||
| BGE |
364,000 | 161,000 | 29 | % | 25 | % | 60 | % | 53 | % | ||||||||||||||
| Pepco |
179,524 | n/a | 22 | % | n/a | 65 | % | n/a | ||||||||||||||||
| DPL |
78,153 | 157 | 15 | % | 0.1 | % | 53 | % | 31 | % | ||||||||||||||
| ACE |
86,780 | n/a | 16 | % | n/a | 51 | % | n/a | ||||||||||||||||
| (a) | In September 2015, the City of Chicago discontinued its participation in the customer choice program and began purchasing its electricity from ComEd. Approximately 670,000 customers were impacted by the City of Chicago’s decision which resulted in the reduction in the number of customers participating in customer choice programs in 2015. |
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. 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.
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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% and 34% of PECO’s, BGE’s and DPL’s 2016-2017 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.
Energy Efficiency Programs. The Utility Registrants are also 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.
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 2017 are $2,200 million, $775 million, $925 million, $625 million, $375 million and $300 million, respectively.
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 in their respective service territories. ACE has yet to receive approval from the NJBPU to proceed with the installation of AMI smart meters.
Transmission Services. The Utility Registrants provide unbundled transmission service under rates approved by FERC. Under FERC’s open access transmission policy promulgated in Order No. 888, 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. 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 PJM region. The Utility Registrants
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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.
PECO’s customers are charged for PECO’s PJM retail transmission services on a full and current basis through a Transmission Service Charge (applicable to default service only) and through a Non-Bypassable Transmission Charge (applicable to all distribution customers) in accordance with PECO’s approved distribution rates.
See Note 3—Regulatory Matters, Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements 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.
As of December 31, 2016, Exelon and its subsidiaries had 34,396 employees in the following companies, of which 11,984 or 35% were covered by collective bargaining agreements (CBAs):
| IBEW Local 15 (a) | IBEW Local 614 (b) | Other CBAs | Total Employees Covered by CBAs |
Total Employees |
||||||||||||||||
| Generation (c) |
1,640 | 99 | 2,635 | 4,374 | 14,717 | |||||||||||||||
| ComEd |
3,777 | — | — | 3,777 | 6,574 | |||||||||||||||
| PECO |
— | 1,310 | — | 1,310 | 2,651 | |||||||||||||||
| BGE (d) |
— | — | — | — | 3,097 | |||||||||||||||
| PHI (e) |
— | — | 331 | 331 | 1,670 | |||||||||||||||
| Pepco (e) |
— | — | 1,056 | 1,056 | 1,466 | |||||||||||||||
| DPL (e) |
— | — | 631 | 631 | 871 | |||||||||||||||
| ACE (e) |
— | — | 399 | 399 | 595 | |||||||||||||||
| Other (f) |
65 | — | 41 | 106 | 2,755 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total |
5,482 | 1,409 | 5,093 | 11,984 | 34,396 | |||||||||||||||
|
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| (a) | A separate CBA between ComEd and IBEW Local 15 covers approximately 62 employees in ComEd’s System Services Group and was renewed in 2016. Generation’s and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022. |
| (b) | 1,310 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 99 employees, which was renewed in 2016 and expiring in 2019. |
| (c) | 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, Pepco Energy Services was allocated to Generation with a total of 358 employees broken down as follows: 229 employees covered by CBAs and 129 non-represented employees. 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 four Security Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 2018 and 2021, respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point which will expire in 2020. Additionally, during 2014, Generation finalized CBAs with the Security Officer unions at Dresden, LaSalle, Limerick and Quad Cities, which expire between 2017 and 2018. Lastly, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018. During 2013, Generation finalized two 3-year agreements: New England ENEH, UWUA Local 369, which will expire in 2017. |
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| (d) | In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 will begin negotiations for an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. |
| (e) | PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions. Collective bargaining agreements are generally renegotiated every three to five years. All of these collective bargaining agreements were renegotiated in 2014 and were extended through various dates ranging from October 2018 through June 2020 |
| (f) | Other includes shared services employees at BSC. |
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 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 and Chief Sustainability Officer; the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation, ComEd, PECO, BGE, 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 Corporate Governance Committee the authority to oversee Exelon’s compliance with laws and regulations and its strategies and efforts to protect and improve the quality of the environment, including Exelon’s climate change and sustainability policies and programs, as discussed in further detail below. The Exelon Board of Directors has also delegated to its Generation Oversight Committee the authority to oversee environmental, health and safety issues relating to Generation. 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 in Illinois, Maryland, Massachusetts, New York, Pennsylvania and Texas in accordance with the Federal Clean Air Act impose restrictions on emission of particulates, sulfur dioxide (SO2), nitrogen oxides (NOx), mercury and other pollutants and require permits for operation of emissions sources. Such permits have been obtained by Exelon’s subsidiaries and must be renewed periodically. The Clean Air Act establishes a comprehensive and complex national program to substantially reduce air pollution from power plants.
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 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 Generation’s power generation facilities
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discharge 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 certain other state and regional agencies and compacts, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.
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 any changes to the existing regulations. For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Peach Bottom, Quad Cities, Riverside and Salem.
On October 14, 2014, the EPA’s final 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.
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 to 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.
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. The Ginna and Nine Mile Point Unit 1 power generation facilities received renewals of their state water discharge permits in 2014.
Salem. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of Salem with its existing cooling water system. In February 2006, PSEG filed a renewal application with the NJDEP allowing Salem to continue operating under its existing NPDES permit until a new permit is issued. On June 30, 2015, NJDEP issued a draft NPDES permit for Salem. The draft permit does not require installation of cooling towers and allows Salem to
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continue to operate utilizing the existing once-through cooling water system with certain required system modifications. On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance.
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 into the environment 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, District of Colombia, Illinois, Maryland, New Jersey and Pennsylvania, 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 are likely to become, 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 24—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, PECO’s and BGE’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. 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. The amount to be expended in 2017 at Exelon for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total $41 million, consisting of $35 million and $6 million respectively, at ComEd and PECO.
Generation’s environmental liabilities primarily arise from contamination at current and former generation and waste storage facilities. As of December 31, 2016, Generation has established appropriate contingent liabilities for potential environmental remediation requirements including contamination attributable to low level radioactive residues at a storage and reprocessing facility named Latty Avenue, and at a disposal facility named West Lake Landfill, both near St. Louis, Missouri related to operations conducted by Cotter Corporation, a former ComEd subsidiary.
The Utility Registrants also have environmental liabilities for remediation considerations. As of December 31, 2016, Generation has established appropriate contingent liabilities for potential environmental remediation requirements.
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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 3—Regulatory Matters and 24—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.
Global Climate Change
Exelon has utility and generation assets, and customers, that are subject to the effects of climate change as described in the Intergovernmental Panel on Climate Change (IPCC) 5th Assessment Report, published in 2014, Accordingly the company is engaged in a variety of initiatives to better understand and develop responses to these issues, including investments in resiliency, partnering with federal, state and local governments and advocating for science-based public policy. Exelon, as a producer of electricity from predominantly low-carbon generating facilities (such as nuclear, hydroelectric, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint, compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does produce GHG emissions, primarily at its fossil fuel-fired generating plants (primarily natural gas); CO2, methane and nitrous oxide are all emitted in this process, with CO2 representing the largest portion of these GHG emissions. GHG emissions from combustion of fossil fuels represented the majority of Exelon’s direct GHG emissions in 2016, although less than 30 percent of its owned generating capacity utilizes fossil fuels with less than 10 percent of owned generation MWh actually produced by fossil fuels as Exelon’s fossil-fired generation is primarily intermediate and peaking in nature. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage in its electric transmission and distribution operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion in its motor vehicles and fossil fuel generation of electricity used to power its facilities. Despite its focus on low-carbon generation, Exelon believes its operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions. 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 climate change regulation or legislation at the Federal, regional and state levels.
International Climate Change Regulation. 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. The Paris Agreement defines the UNFCCC’s objective of limiting the global temperature increase to 1.5°C above pre-industrial levels. All Parties are required to develop their own national emission reductions and to update those reductions at least every five years. The Developed Country Parties, including the United States, are required to take the lead by undertaking economy-wide absolute emission reduction targets. The United States had previously submitted its national emission reductions to achieve a 2020 target of reducing net emissions to 17% below the 2005 level and to achieve net greenhouse gas emission reductions of 26%—28% below the 2005 level by 2025. The United States has indicated that it intends to achieve these reductions through a variety of mechanisms, including regulations to cut carbon pollution from new and existing power plants. The Paris Agreement entered into force on November 4, 2016 the thirtieth day after the date on which at
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least 55 Parties accounting for at least an estimated 55% of total global greenhouse gas emissions ratified the Agreement. The Agreement has not been ratified by the US Senate and it is uncertain whether or not or to what extent the new Trump Administration will pursue the established target.
Federal Climate Change Legislation and Regulation. It is highly uncertain that Federal legislation to reduce GHG emissions will be enacted. If such legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits.
Under the Obama Administration, the EPA proposed and finalized regulations for new and modified fossil-fuel power plants under Section 111(b) of the Clean Air Act and Section 111(d) for existing fossil-fuel power plants. These regulations are currently being litigated. The 111(d) regulations, referred to as the Clean Power Plan, are currently subject to a stay by the Supreme Court, pending conclusion of all litigation at both the D.C. Circuit and Supreme Court levels. The D.C. Circuit heard en banc oral argument in late September 2016, but has not yet issued its decision. Prior to the stay, the Clean Power Plan had established GHG emission reduction targets for each state, with emission reductions slated to begin in 2022. State requirements to submit plans to EPA in September 2016 (or within two years if an extension was requested) were placed in abeyance pending results of litigation.
President Trump’s election platform called for eliminating a number of EPA regulations, including the Clean Power Plan. Due to the need to appoint and confirm key EPA officials as the Trump Administration begins to govern, the specific details of the Trump Administration’s plans to address the Clean Power Plan are not known. In the interim, the D.C. Circuit continues its review of the regulation under existing litigation and is expected to issue its decision in the first half of 2017.
Due to current litigation and the need for the new Administration to develop its approach to dealing with the Clean Power plan, Exelon and Generation cannot at this time predict the future of the Clean Power Plan or individual state responses to Clean Power Plan developments or how developments will impact their future financial positions, results of operations and cash flows.
Regional and State Climate Change Legislation and Regulation. After a two-year program review, the nine northeast and mid-Atlantic states currently participating in the Regional Greenhouse Gas Reduction Initiative (RGGI) released an updated RGGI Model Rule and Program Review Recommendations Summary on February 7, 2013. Under the updated RGGI program the regional RGGI CO2 budget was reduced, starting in 2014, from its previous 165 million ton level to 91 million tons, with a 25 percent reduction in the cap level each year from 2015 through 2020. Included in the program are provisions for cost containment reserve (CCR) allowances, which will become available if the total demand for allowances, above the CCR trigger price, exceeds the number of CO2 allowances available for purchase at auction. (CCR trigger prices are $6 in 2015, $8 in 2016 and $10 in 2017; after 2017 the CCR price increases by 2.5 percent each year). Allowance prices in 2016 remained below the applicable CCR trigger price, indicating program costs remained within the boundaries of costs acceptable to participating states. During 2016, RGGI began its quadrennial review process to determine what, if any, program design amendments should be pursued for the regional program. A series of stakeholder calls occurred in 2016, which included discussion around potential linkage issues with the federal Clean Power Plan, linkages to state GHG emission reduction goals/programs, functioning of cost containment mechanisms, and consideration of whether future cap levels should be adjusted for the post-2020 period. RGGI intends to complete its program review in early 2017.
On December 18, 2009, Pennsylvania issued the state’s final Climate Change Action Plan. The plan sets as a target a 30 percent reduction in GHG emissions by 2020. The Climate Change Advisory Committee continues to meet quarterly to review Climate Action Work Plans for the residential, commercial and industrial sectors. The Climate Change Action Plan does not impose any requirements on Generation or PECO at this time.
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The Maryland Commission on Climate Change was chartered in 2007 and released a greenhouse gas reduction strategy with 42 recommendations on August 27, 2008. The plan’s primary policy recommendation to formally adopt science-based regulatory goals to reduce Maryland’s green house gas emissions (GHG) was realized with the passage of the Greenhouse Gas Emissions Reduction Act of 2009 (GGRA) which required Maryland to reduce its GHG emissions by 25 percent below 2006 levels by 2020. It also directed the Maryland Department of Environment to prepare and implement an action plan which listed Maryland’s electricity consumption reduction goals, required under the “EmPOWER Maryland” program, and mandatory State participation in RGGI Program, as the energy sector’s contribution to the plan. In April 2016, the Governor of Maryland signed the GGRA of 2016 into law, which updated the state’s Climate Commission charter. It expanded membership to include more non-governmental members and established an enhanced statewide GHG emissions reduction target of 40 percent from 2006 levels by 2030, maintaining the caveats from the 2007 legislation that the implementation have a net positive impact on both jobs and the economy. MDE is currently working on plans to meet the 2016 GGRA requirements. In February of this year (2017) , the Maryland General Assembly overrode Maryland Governor Hogan’s veto of legislation that requires the current Renewable Portfolio Standard (RPS) to be accelerated and enhanced. The law requires the RPS, previously set at 20% renewables by 2022, with a 2% solar carve out, to move to 25% renewables by 2020 with a 2.5% solar carve out.
Exelon’s Voluntary Climate Change Efforts. In a world increasingly concerned about global climate change and regulatory action to reduce GHG, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon remains one of the largest, lowest carbon electric generators in the United States: nuclear for base load, natural gas for marginal and peak demand, hydro and pumped storage, and supplemental wind and solar renewables. As further legislation and regulation imposing requirements on emissions of GHG and air pollutants are promulgated, Exelon’s low-carbon, low-emission generation fleet will position the company to benefit from its comparative advantage over other generation fleets.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia have adopted some form of RPS requirement. Illinois, Pennsylvania, Maryland, the District of Columbia, Delaware and New Jersey have laws specifically addressing energy efficiency and renewable energy initiatives. In addition to state level activity, RPS legislation has been considered and may be considered again in the future by the United States Congress. Also, states that currently do not have RPS requirements may adopt such legislation in the future.
In Illinois, in accordance with legislation in effect on December 31, 2016, the IPA’s Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of December 31, 2016, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.
In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 (11.5% of retail load by June 1 2016 growing to 25% by June 1 2025) although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each Retail
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Electric Supplier and each utility is responsible for the renewable resource obligation for the customers to which it supplies power. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.
Originally passed November 30, 2004 the AEPS Act became effective for PECO on January 1, 2011. During 2016, PECO was required to supply approximately 5.5% of electric energy generated from Tier I alternative energy resources (including solar, wind power, low-impact hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within Pennsylvania), as measured in AECs, through May 31, 2016 and subsequently 6.0% beginning June 1, 2016 and continuing through May 31, 2017. PECO is also required to supply 8.2% of electric energy generated from Tier II alternative energy resources (including waste coal, demand-side management, large-scale hydropower, municipal solid waste, generation of electricity utilizing wood and by-products of the pulping process and wood, distributed generation systems and integrated combined coal gasification technology), as measured in AECs, effective June 1, 2015 and continuing through May 31, 2020. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for Tier II by 2021. In order to comply with these requirements, PECO purchases its AECs through its DSP Program full requirement contracts with various counterparties, including Generation. PECO also obtains AECs of Solar Tier I annually from long term agreements with various counterparties, including Generation, and balancing amounts of Tier 1 non-solar and Tier II through broker purchases.
Section 7-703 of the Public Utilities Article in Maryland sets forth the RPS requirement, which applies to all retail electricity sales in Maryland by electricity suppliers. The RPS requirement requires that suppliers obtain a specified percentage of the electricity it sells from Tier 1 sources (solar, wind, biomass, methane, geothermal, ocean, fuel cell, small hydroelectric, and poultry litter) and Tier 2 sources (hydroelectric, other than pump storage generation, and waste-to-energy). The RPS requirement began in 2006, requiring that suppliers procure 1.0% and 2.5% from Tier 1 and Tier 2 sources, respectively, escalating in 2022 to 22.0% from Tier 1 sources, including at least 2.0% from solar energy, and a phase out of Tier 2 resource options by 2022. In 2015, 10.5% was required from Tier 1 renewable sources, including at least 0.5% derived from solar energy and 2.5% from Tier 2 renewable sources. BGE, Pepco and DPL are subject to requirements established by the Public Utilities Article in Maryland related to the use of alternative energy resources. In addition, the wholesale suppliers that supply power to BGE, Pepco and DPL through SOS procurement auctions have the obligation, by contract with BGE, Pepco and DPL, to meet the RPS requirements.
Section 34-1432 of the D.C. Code sets forth the RPS requirement, which applies to all retail electricity sales in the District of Columbia by electricity suppliers. The RPS requirement requires that suppliers obtain a specified percentage of the electricity it sells from Tier 1 sources (solar, wind, certain qualifying biomass, methane from anaerobia decomposition of organic materials in landfill or wastewater treatment plant, geothermal, ocean, and fuel cell) and Tier 2 sources (hydroelectric (other than pumped storage generation), certain qualifying biomass and waste-to-energy). The RPS requirement began in 2007, with standards increasing annually. For 2017, the RPS requires that suppliers procure 13.1% and 2.5% from Tier 1 and Tier 2 sources, respectively, with not less than 0.95% solar, and escalating in 2023 to 20.0% from Tier 1 sources, including at least 2.5% from solar energy, and a phase out of Tier 2 resource options. In 2015 the law was amended to extend the RPS requirements to 2032, at which time not less than 50% is required from Tier 1 renewable sources, including at least 5.0% derived from solar energy. Tier 2 renewable sources remain phased out. The wholesale suppliers that supply power to Pepco through SOS procurement auctions have the obligation, by contract with Pepco, to meet the RPS requirements.
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Title 26 of the Delaware Code sets forth the RPS requirement, which applies to retail electricity sales in Delaware by electricity suppliers. The RPS requirement requires that DPL obtain a specified percentage of the electricity it delivers to its eligible customers from eligible energy resources (solar electric, wind, ocean tidal, ocean thermal, fuel cells powered by renewable fuels, hydroelectric facilities with a maximum capacity of 30 MW, sustainable biomass, anaerobic digestion and landfill gas). The RPS requirement, beginning in 2007, required that suppliers procure 2.0% from eligible energy resources, with not less than 0.011% from solar, and escalating annually through 2025, at which time suppliers must procure 25.0% from eligible energy resources, including at least 3.5% from solar. As of December 31, 2016, DPL is a party to three land-based wind power purchase agreements in the aggregate amount of 128 MWs (nameplate capacity). DPL has contracted for approximately 48 MW of Solar Renewable Energy Credits (SRECs) through a combination of long term SREC purchase agreements with solar facilities, SREC Purchase agreements with the Delaware Sustainable Energy Utility and the DE SREC Procurement Program. On October 18, 2011, the DPSC approved a tariff submitted by DPL in accordance with the requirements of the RPS specific to a fuel cell facility totaling 30 MWs to be constructed by a qualified fuel cell provider. The tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the qualified fuel cell provider for each MWh of energy produced by the fuel cell facilities through 2033. The qualified fuel cell provider output reduces the non-solar and/or solar requirements needed to satisfy the Delaware RPS obligations.
The Electric Discount and Energy Competition Act, (“EDECA”), was signed into law in 1999, and includes the requirement for compliance with New Jersey’s RPS by electric power suppliers and providers of BGS. The RPS requires that electric power suppliers obtain a specified percentage of the electricity they sell from Class I sources (solar, wind, wave/tidal action, geothermal, methane captured from landfills, fuel cells with certain types of power sources, and biomass) and Class II sources (hydroelectric facilities with a combined design capacity of less than 30 MW, and certain resource recovery facilities). In 2010, the Solar Energy Advancement and Fair Competition Act, (“SEAFCA”), was signed into law. SEAFCA amended several provisions of EDECA, among them the manner in which suppliers were to comply with the solar portion of the RPS. SEAFCA, beginning in energy year 2011, set out a specific requirement for solar energy generation. The Solar Act of 2012 made further changes effective for energy year 2014 and beyond. The RPS requirement has changed over time. For energy year 2005, suppliers were required to procure 0.74% and 2.5% from Class I and Class II sources, respectively. For the most recently completed energy year 2016, 9.649% was required from Class I renewable sources, 2.5% from Class II renewable sources, and 2.75% from solar energy. As noted above, the RPS applies to each supplier or provider that sells electricity to retail customers in New Jersey. Pursuant to Section 14:4-1.2 of the New Jersey Administrative Code, electric public utilities, such as ACE, that provide electric generation services only for the purpose of providing BGS are not electric power suppliers and so are not subject to the RPS procurement requirements.
Similar to ComEd, PECO, BGE, Pepco, DPL and ACE, Generation’s retail electric business must source a portion of the electric load it serves in many of the states in which it does business from renewable resources or approved equivalents such as RECs. Potential regulation and legislation regarding renewable and alternative energy resources could increase the pace of development of wind and other renewable/alternative energy resources, which could put downward pressure on wholesale market prices for electricity in some markets where Exelon operates generation assets. At the same time, such developments may present some opportunities for sales of Generation’s renewable power, including from wind, solar, hydroelectric and landfill gas.
See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
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Executive Officers of the Registrants as of February 13, 2017
Exelon
| Name |
Age | Position |
Period | |||
| Crane, Christopher M. |
58 | Chief Executive Officer, Exelon | 2012 - Present | |||
| Chairman, ComEd, PECO & BGE | 2012 - Present | |||||
| Chairman, PHI | 2016 - Present | |||||
| President, Exelon | 2008 - Present | |||||
| President, Generation | 2008 - 2013 | |||||
| Chief Operating Officer, Exelon | 2008 - 2012 | |||||
| Cornew, Kenneth W. |
51 | 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 | |||||
| Senior Vice President, Exelon; President, Power Team | 2008 - 2012 | |||||
| O’Brien, Denis P. |
56 | Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon Utilities | 2012 - Present | |||
| Vice Chairman, ComEd, PECO, BGE | 2012 - Present | |||||
| Vice Chairman, PHI | 2016 - Present | |||||
| Chief Executive Officer, PECO; Executive Vice President, Exelon | 2007 - 2012 | |||||
| President and Director, PECO | 2003 - 2012 | |||||
| Pramaggiore, Anne R. |
58 | Chief Executive Officer, ComEd | 2012 - Present | |||
| President, ComEd | 2009 - Present | |||||
| Chief Operating Officer, ComEd | 2009 - 2012 | |||||
| Adams, Craig L. |
64 | President and Chief Executive Officer, PECO | 2012 - Present | |||
| Senior Vice President and Chief Operating Officer, PECO | 2007 - 2012 | |||||
| Butler, Calvin G. |
47 | 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. |
57 | 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. |
63 | Senior Executive Vice President and Chief Strategy Officer, Exelon | 2012 - Present | |||
| Executive Vice President, Finance and Legal, Exelon | 2009 - 2012 | |||||
| Thayer, Jonathan W. |
45 | Senior Executive Vice President and Chief Financial Officer, Exelon | 2012 - Present | |||
| Senior Vice President and Chief Financial Officer, Constellation Energy; Treasurer, Constellation Energy | 2008 - 2012 | |||||
| Aliabadi, Paymon |
54 | Executive Vice President and Chief Enterprise Risk Officer, Exelon | 2013 - Present | |||
| Managing Director, Gleam Capital Management | 2012 - 2013 | |||||
| DesParte, Duane M. |
53 | Senior Vice President and Corporate Controller, Exelon | 2008 - Present |
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Generation
| Name |
Age | Position |
Period | |||
| Cornew, Kenneth W. |
51 | 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 | |||||
| Senior Vice President, Exelon; President, Power Team | 2008 - 2012 | |||||
| Pacilio, Michael J. |
56 | Executive Vice President and Chief Operating Officer, Exelon Generation | 2015 - Present | |||
| President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer, Generation | 2010 - 2015 | |||||
| Chief Operating Officer, Exelon Nuclear | ||||||
| Hanson, Bryan C. |
51 | President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President, Exelon Generation | 2015 - Present | |||
| Nigro, Joseph |
52 | Executive Vice President, Exelon; Chief Executive Officer, Constellation | 2013 - Present | |||
| Senior Vice President, Portfolio Management and Strategy | 2012 - 2013 | |||||
| Vice President, Structuring and Portfolio Management, Exelon Power Team | 2010 - 2012 | |||||
| DeGregorio, Ronald |
54 | Senior Vice President, Generation; President, Exelon Power | 2012 - Present | |||
| Chief Integration Officer, Exelon | 2011 - 2012 | |||||
| Wright, Bryan P. |
50 | Senior Vice President and Chief Financial Officer, Generation | 2013 - Present | |||
| Senior Vice President, Corporate Finance, Exelon | 2012 - 2013 | |||||
| Chief Accounting Officer, Constellation Energy | 2009 - 2012 | |||||
| Vice President and Controller, Constellation Energy | 2008 - 2012 | |||||
| Bauer, Matthew N. |
40 | Vice President and Controller, Generation | 2016 - Present | |||
| Vice President and Controller, BGE | 2014 - 2016 | |||||
| Vice President of Power Finance, Exelon Power | 2012 - 2014 | |||||
| Director, FP&A and Retail, Constellation | 2012 - 2012 | |||||
| Executive Director, Corporate Development, Constellation | 2009 - 2012 |
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ComEd
| Name |
Age | Position |
Period | |||
| Pramaggiore, Anne R. | 58 | Chief Executive Officer, ComEd | 2012 - Present | |||
| President, ComEd | 2009 - Present | |||||
| Chief Operating Officer, ComEd | 2009 - 2012 | |||||
| Donnelly, Terence R. | 56 | Executive Vice President and Chief Operating Officer, ComEd | 2012 - Present | |||
| Executive Vice President, Operations, ComEd | 2009 - 2012 | |||||
| Trpik Jr., Joseph R. | 47 | Senior Vice President, Chief Financial Officer and Treasurer, ComEd | 2009 - Present | |||
| Jensen, Val | 61 | Senior Vice President, Customer Operations, ComEd | 2012 - Present | |||
| Vice President, Marketing and Environmental Programs, ComEd | 2008 - 2012 | |||||
| Gomez, Veronica | 47 | 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 | 55 | Senior Vice President, Governmental and External Affairs, ComEd | 2012 - Present | |||
| Senior Vice President, Customer Operations, ComEd | 2009 - 2012 | |||||
| Brookins, Kevin B. | 55 | Senior Vice President, Strategy & Administration, ComEd | 2012 - Present | |||
| Vice President, Operational Strategy and Business Intelligence, ComEd | 2010 - 2012 | |||||
| McGuire, Timothy M. | 58 | Senior Vice President, Distribution Operations, ComEd | 2016 - Present | |||
| Vice President, Transmission and Substations, ComEd | 2010 - 2016 | |||||
| Kozel, Gerald J. | 44 | Vice President, Controller, ComEd | 2013 - Present | |||
| Assistant Corporate Controller, Exelon | 2012 - 2013 | |||||
| Director of Financial Reporting and Analysis, Exelon | 2009 - 2012 |
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PECO
| Name |
Age | Position |
Period | |||
| Adams, Craig L. |
64 | President and Chief Executive Officer, PECO | 2012 - Present | |||
| Senior Vice President and Chief Operating Officer, PECO | 2007 - 2012 | |||||
| Barnett, Phillip S. |
53 | Senior Vice President and Chief Financial Officer, PECO | 2007 - Present | |||
| Treasurer, PECO | 2012 - Present | |||||
| Innocenzo, Michael A. |
51 | Senior Vice President and Chief Operations Officer, PECO | 2012 - Present | |||
| Vice President, Distribution System Operations and Smart Grid/Smart Meter, PECO | 2010 - 2012 | |||||
| Webster Jr., Richard G. |
55 | Vice President, Regulatory Policy and Strategy, PECO | 2012 - Present | |||
| Director of Rates and Regulatory Affairs | 2007 - 2012 | |||||
| Murphy, Elizabeth A. |
57 | Senior Vice President, Governmental and External Affairs, PECO | 2016 - Present | |||
| Vice President, Governmental and External Affairs, PECO | 2012 - 2016 | |||||
| Director, Governmental & External Affairs, PECO | 2007 - 2012 | |||||
| Jiruska, Frank J. |
56 | Vice President, Customer Operations, PECO | 2013 - Present | |||
| Diaz Jr., Romulo L. |
70 | Vice President and General Counsel, PECO | 2012 - Present | |||
| Vice President, Governmental and External Affairs, PECO | 2009 - 2012 | |||||
| Bailey, Scott A. |
40 | Vice President and Controller, PECO | 2012 - Present | |||
| Assistant Controller, Generation | 2011 - 2012 |
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BGE
| Name |
Age | Position |
Period | |||
| Butler, Calvin G. | 47 | 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. | 49 | President, BGE | 2014 - Present | |||
| Chief Operating Officer, BGE | 2012 - Present | |||||
| Senior Vice President, BGE | 2009 - 2014 | |||||
| Vice President and Chief Integration Officer, Constellation Energy | 2011 - 2012 | |||||
| Case, Mark D. | 55 | Vice President, Strategy and Regulatory Affairs, BGE | 2012 - Present | |||
| Senior Vice President, Strategy and Regulatory Affairs, BGE | 2007 - 2012 | |||||
| Biagiotti, Robert D. | 47 | Vice President, Customer Operations and Chief Customer Officer, BGE | 2015 - Present | |||
| Vice President, Gas Distribution, BGE | 2011 - 2015 | |||||
| Gahagan, Daniel P. | 63 | Vice President and General Counsel, BGE | 2007 - Present | |||
| Vahos, David M. | 44 | 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 | |||||
| Executive Director, Audit, Constellation | 2010 - 2012 | |||||
| Holmes, Andrew W. | 48 | Vice President and Controller, BGE | 2016 - Present | |||
| Director, Generation Accounting, Exelon | 2013 - 2016 | |||||
| Director, Derivatives and Technical Accounting, Exelon | 2008 - 2013 | |||||
| Núñez, Alexander G. | 45 | 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 |
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PHI, Pepco, DPL and ACE
| Name |
Age | Position |
Period | |||
| Velazquez, David M. | 57 | 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 | 52 | 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. | 49 | Senior Vice President and Chief Financial Officer, PHI, Pepco, DPL and ACE | 2016 - Present | |||
| Vice President, Treasurer and Chief Risk Officer, Pepco Holdings | 2012 - Present | |||||
| Bonney, Paul R. | 58 | Senior Vice President, Legal and Regulatory Strategy, PHI, Pepco, DPL and ACE | 2016 - Present | |||
| Senior Vice President and General Counsel, Constellation Energy | 2012 - 2016 | |||||
| Parker, Kenneth J. | 54 | Senior Vice President, Governmental and External Affairs, PHI, Pepco, DPL and ACE | 2016 - Present | |||
| Senior Vice President, Government Affairs and Corporate Citizenship, Pepco Holdings, Inc. | 2012 - 2016 | |||||
| Stark, Wendy E. | 44 | Vice President and General Counsel, PHI, Pepco DPL and ACE | 2016 - Present | |||
| Deputy General Counsel, Pepco Holdings, Inc. | 2012 - Present | |||||
| McGowan, Kevin M. | 55 | Vice President, Regulatory Policy and Strategy | 2016 - Present | |||
| Vice President, Regulatory Affairs, Pepco Holdings, Inc. | 2012 - 2016 | |||||
| Aiken, Robert M. | 50 | Vice President and Controller, PHI, Pepco, DPL and ACE | 2016 - Present | |||
| Vice President and Controller, Generation | 2012 - 2016 | |||||
| Executive Director and Assistant Controller, Constellation | 2011 - 2012 |
| ITEM 1A. | RISK FACTORS |
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 Enterprise Risk Officer and the RMC, which comprises officers of the Registrants, to identify and evaluate the most significant risks of the Registrants’ businesses and the appropriate steps to manage and mitigate those risks. The Chief Enterprise 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’ results of operations or cash flows 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.
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Exelon’s financial condition and results of operations 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 financial condition and results of operations 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, and (4) the impacts of on-going competition in the retail channel. |
| • | 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 cost recovery 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, 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 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 and safety of its energy delivery systems are fundamental to Exelon’s ability to protect and grow shareholder value. Additionally, the operating costs of the Utility Registrants and the opinions of their customers and regulators, are affected by those companies’ ability to maintain the reliability and safety of their energy delivery systems. |
| • | Risks Related to the PHI Merger. Exelon is subject to additional risks related to the merger with PHI that 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 or cash flows. (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 subject to variability of spot and forward market prices in the markets in which it operates rise and fall.
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. 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 new technologies to recover natural gas from shale deposits has increased natural gas supply and reserves, placing downward pressure on natural gas
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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: 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. Increased supply in excess of demand is furthered by the continuation of RPS mandates and subsidies for renewable energy.
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 results of operations or cash flows, 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 other discretionary uses of cash such as growth projects or to pay dividends. 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 position. See Note 9—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. 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
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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 shale gas development or sources, cost-effective renewable energy technologies, broad consumer adoption of electric vehicles, distributed generation and energy storage devices. Such developments could affect the price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to our distribution systems to address changing load demands and could 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 or financial position 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
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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 and financial position 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, their results of operations, cash flows or financial position 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 or financial position. (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. Disruptions in the European markets could reduce or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2016, approximately 23%, or $2.2 billion of the Registrants’ available credit facilities were with European banks. The credit facilities include $9.5 billion in aggregate total commitments of which $7.9 billion was available as of December 31, 2016. As of December 31, 2016, there was $75 million of borrowings under Generation’s bilateral credit facilities. See Note 14—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 or cash flows.
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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 rights to foreclose against the project assets and related collateral.
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 liquidity. 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-
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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 Liquidity and Capital Resources—Recent Market Conditions and Security Ratings for further 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 or cash flows 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 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, operating results, cash flows or financial position.
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.
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 and effectively address the changes in the wholesale power markets.
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Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions, could negatively impact the Registrants’ results of operations or cash flows. (All Registrants)
Potential Corporate Tax Reform. The results of the November 2016 U.S. elections have introduced greater uncertainty with respect to federal tax policies. President Trump has stated that one of his top priorities is comprehensive tax reform and House Republicans plan to advance their tax reform “blueprint”. Tax reform proposals call for a reduction in the corporate federal income tax rate from the current 35% to as low as 15%. Other proposals provide, among other items, for the immediate deduction of capital investment expenditures and full or partial elimination of debt interest expense deductions. It is uncertain whether, to what extent or when these or any other changes in federal tax policies will be enacted or the transition time frame for such changes. Further, for the Utility Registrants, regulators may impose rate reductions to provide the benefit of any income tax expense reductions to customers and refund “excess” deferred income taxes previously collected through rates. The amounts and timing of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.
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 appeals 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 Notes 1—Significant Accounting Policies and Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates 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 or cash flows. (All Registrants)
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, 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. For DPL, purchased natural gas costs are charged to customers using a GCR mechanism that compares the actual cost of gas to a forecasted amount. The difference between the actual cost and the forecast is fully recoverable and carried forward as a recovery balance in the next GCR filing. 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 effect on the Registrants’ results of operations or cash flows. Also, the Utility Registrants’ cash flows could be affected by differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
Further, 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
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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 impact the Utility Registrants’ results of operations or cash flows. 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 or cash flows. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for further discussion of the Registrants’ credit risk.
The effects of weather could impact the Registrants’ results of operations or cash flows. (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 ComEd, PECO, DPL and ACE. Due to revenue decoupling, BGE, Pepco and DPL 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 Illinois FEJA signed into law on December 2016 and effective in 2017, ComEd can eliminate the favorable or unfavorable impacts of weather or load on its electric distribution revenues by either (1) revising its electric distribution formula rate to eliminate the ROE collar beginning with the reconciliation performed for the 2017 calendar year or (2) implementing a decoupling tariff if the electric distribution formula rate were to be terminated at anytime.
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 on the Utility Registrants’ results of operations or cash flows. 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 62%, 54%, 68%, 70%, 81%, 76%, 79% and 73% of total assets for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of December 31, 2016. In addition, Exelon and Generation have significant balances related to unamortized energy contracts, as further disclosed in Note 11—Intangible Assets of the Combined Notes to Consolidated Financial Statements. The Registrants evaluate the recoverability of
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the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such as 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 on the Registrants’ results of operations.
As of December 31, 2016, 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 7—Property, Plant and Equipment, Note 8—Impairment of Long Lived Assets and Note 11—Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional discussion 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 on the operating results, financial condition, or cash flows 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 asset and a Registrant could incur substantial costs to fulfill its obligations under these indemnities.
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
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Registrant could be held responsible for the obligations, which could impact that Registrant’s results of operations, cash flows or financial position. In connection with Exelon’s 2001 corporate restructuring, Generation assumed certain of ComEd’s and PECO’s rights and obligations with respect to their former generation businesses. Further, ComEd and PECO may have entered into agreements with third parties under which the third-party agreed to indemnify ComEd or PECO 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 or Generation experienced events that reduced its creditworthiness or the indemnity arrangement became unenforceable, ComEd or PECO could be liable for any existing or future claims, which could impact ComEd’s or PECO’s results of operations, cash flows or financial position.
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 operations or financial results. 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 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 operating results and cash flows are significantly affected by Generation’s sale of power at market-based rates, as opposed to cost-based or other similarly regulated rates, and Exelon’s and the Utility Registrants’ operating results and cash flows are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power 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 or financial position.
Regulatory and legislative developments related to climate change and RPS could also significantly affect Exelon’s and Generation’s results of operations, cash flows or financial position. 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. 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 greenhouse gas emission 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. 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.
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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 65% 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, such as PJM’s, and (2) the absence of material changes to market structures that would limit or otherwise negatively affect market competitiveness. Generation could also be adversely affected by state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize new generation, such as the subsequently dismissed New Jersey Capacity Legislation and the MDPSC’s RFP for new gas-fired generation in Maryland. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details related to the New Jersey Capacity Legislation and the Maryland new electric generation requirements.
In addition, FERC’s application of its Order 697 and its subsequent revisions could pose a risk that Generation will have difficulty satisfying 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 applies to Exelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the creation of 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. For non security-based swaps including commodity swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are either swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser degree to end-users of swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements swaps used by end-users to hedge or mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks using swaps without being subject to mandatory clearing, and accepts or exempts end-users from many of the other substantive regulations. Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not require registration with the CFTC as an SD or MSP. Generation does not anticipate transacting in the future in a manner in which it would become a SD or MSP.
There are, however, some rulemaking proceedings that have not yet been finalized, including the capital and margin rules for (non-cleared) swaps. Generation does not expect these rules to directly impact its collateral requirements. However, depending on the substance of these final rules in addition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s swap counterparties could be subject to additional and potentially significant
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capitalization requirements. These regulations could motivate the SDs and MSPs to increase collateral requirements or cash postings from their counterparties, including Generation.
Generation continues to monitor the rulemaking proceedings with respect to the capital and margin rules, but cannot predict to what extent, if any, further refinements to Dodd-Frank requirements could impact its cash flows or financial position, but such impacts could be material.
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. The prospect of such 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
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retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance. Pursuant to discussions with the NJDEP 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. On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers. However, the permit is being challenged by an environmental organization, and if successful, could result in additional costs for Clean Water Act compliance.
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 24—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, 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
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rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs and could have a material adverse effect on the Utility Registrants’ results of operations, cash flows and financial position. See Note 3—Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for 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 or cash flows of Generation and the Utility Registrants. (All Registrants)
Changes to current state legislation or the development of Federal legislation that requires the use of 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, 2016, 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. At December 31, 2016, the gain (loss) could have been as much as $2.5 billion, $(1.1) billion, $(552) million, $(821) million, $(208) million and $(476) million (before taxes) as a result of the elimination of regulatory assets and liabilities of ComEd, PECO, BGE, Pepco, DPL and ACE, respectively. Further, Exelon would record a charge against OCI (before taxes) of up to $2.6 billion, $614 million, $424 million, $243 million, and $84 million for ComEd, BGE, Pepco, DPL and ACE respectively, related to Exelon’s net regulatory assets associated with its defined benefit postretirement plans. Exelon also has a net regulatory liability of $47 million (before taxes) associated with PECO’s defined benefit postretirement plans that would result in an increase in OCI if reversed. 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 Notes 1—Significant Accounting Policies, 3—Regulatory Matters and 11—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.
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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. In 2009, select Northeast and Mid-Atlantic states implemented a model rule, developed via the RGGI, to regulate CO2 emissions from fossil-fired generation. RGGI states are working on updated programs to further limit emissions, and the EPA has introduced regulation to address greenhouse gases from new fossil plants that could potentially impact existing plants. 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, more stringent permitting requirements could preclude the construction of lower-carbon nuclear and gas-fired power plants. Similarly, 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, see ITEM 1. BUSINESS “Global Climate Change” and Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
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 3—Regulatory Matters and Note 24—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
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subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent regulatory requirements. Unfavorable regulatory outcomes can include the enactment of more stringent laws and regulations governing Exelon’s operations, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative impact on the Registrants’ business, results of operations, cash flows and financial positions.
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 or financial position. (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 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require significant expenditures that could have a material adverse effect on the Registrants’ results of operations.
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 results of operations or financial position. 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 currently estimates 2030 to be the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation. 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 or cash flows.
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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, 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’ operations and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry in general and on Exelon in particular 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, which could adversely affect the Registrants’ results of operations and its 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.
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In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property and casualty 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.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Certain of Generation’s nuclear units have previously had a limited number of fuel performance issues. 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 shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For 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 or financial position. 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
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nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations or financial position. 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 affect Generation’s results of operations or financial position.
Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance. The required amount of nuclear liability insurance is $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 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 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional discussion of nuclear insurance.
Decommissioning. 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 trust 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.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. The performance of capital markets also 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 or financial position could be significantly affected. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 cash flows or financial position 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 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
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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 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, ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability.
In the case of the nuclear units subject to the regulatory agreements with the ICC, if the funds held in the NDT funds for any former ComEd unit are 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 results of operations and financial position 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 Statement of Operations and Comprehensive Income.
In the case of 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 and financial position could be material. Additionally, any remaining balances in noncurrent payables to affiliates at Generation and PECO’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 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 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 will renew 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 and significantly affect Generation’s results of operations or financial position. 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.
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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, financial condition, or cash flows 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 or infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS for further 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 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 or financial condition 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 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 employee 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 or cash flows. See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding proceedings related to storm-related outages in ComEd’s service territory.
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. (All 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
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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 Registrant’s 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 on their and Exelon’s results of operations, cash flows and financial position.
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 increase the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their competitors, 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 subject the Registrants to financial harm associated with 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 we have been, and will likely continue to be, subjected to physical and cyber-attacks, to date we have not experienced a material breach or disruption to our 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 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, any of which could contribute to the loss of customers and have a negative impact on the business and/or results of operations. 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 and financial position.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ results of operations. (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
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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 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, 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 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 on the Utility Registrants’ financial results.
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)
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 future business, financial condition, operating results and prospects.
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
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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.
Exelon could incur unexpected transaction fees and merger-related costs in connection with the merger. (Exelon, PHI, Pepco, DPL and ACE)
Exelon is incurring costs to combine the operations of Exelon, PHI and its subsidiaries. Exelon and PHI could incur additional unanticipated costs in the integration of the businesses of the two companies. Although Exelon and PHI expect that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Exelon could encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements associated with regulatory approvals for the PHI Merger. (Exelon, PHI, Pepco, DPL and ACE)
As a result of the process to obtain regulatory approvals required for the PHI Merger, Exelon is committed to various programs, contributions and investments in several settlement agreements and regulatory approval orders, one of which may remain subject to the “most favored nation” reconciliation process. It is possible that Exelon could encounter delays, unexpected difficulties, or additional costs in meeting these commitments in compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in increased costs or result in penalties or fines that could adversely affect Exelon’s, PHI’s, Pepco’s, DPL’s and ACE’s financial position and operating results.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
All Registrants
None.
65
Table of Contents
| ITEM 2. | PROPERTIES |
The following table describes Generation’s interests in net electric generating capacity by station at December 31, 2016:
|
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 | 2,383 | ||||||||||||||||||||||
| 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 | (f) | ||||||||||||||||||||
| Clinton |
Midwest | Clinton, IL | 1 | Uranium | Base-load | 1,069 | ||||||||||||||||||||||
| Michigan Wind 2 |
Midwest | Sanilac Co., MI | 50 | Wind | Base-load | 90 | ||||||||||||||||||||||
| Beebe |
Midwest | Gratiot Co., MI | 34 | Wind | Base-load | 82 | ||||||||||||||||||||||
| Michigan Wind 1 |
Midwest | Huron Co., MI | 46 | Wind | Base-load | 69 | ||||||||||||||||||||||
| Harvest 2 |
Midwest | Huron Co., MI | 33 | Wind | Base-load | 59 | ||||||||||||||||||||||
| Harvest |
Midwest | Huron Co., MI | 32 | Wind | Base-load | 53 | ||||||||||||||||||||||
| Beebe 1B |
Midwest | Gratiot Co., MI | 21 | Wind | Base-load | 50 | ||||||||||||||||||||||
| Ewington |
Midwest | Jackson Co., MN | 10 | 99 | Wind | Base-load | 20 | (f) | ||||||||||||||||||||
| Marshall |
Midwest | Lyon Co., MN | 9 | 99 | Wind | Base-load | 19 | (f) | ||||||||||||||||||||
| City Solar |
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) | ||||||||||||||||||||
| CP Windfarm |
Midwest | Faribault Co., MN | 2 | Wind | Base-load | 4 | ||||||||||||||||||||||
| Blue Breezes |
Midwest | Faribault Co., MN | 2 | Wind | Base-load | 3 | ||||||||||||||||||||||
| Solar Ohio |
Midwest | Toledo, OH | 3 | Solar | Base-load | 3 | ||||||||||||||||||||||
| Southeast Chicago |
Midwest | Chicago, IL | 8 | Gas | Peaking | 296 | ||||||||||||||||||||||
| Clinton Battery Storage |
Midwest | Blanchester, OH | 1 | Energy Storage | Peaking | 10 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Total Midwest |
12,150 | |||||||||||||||||||||||||||
| Limerick |
Mid-Atlantic | Sanatoga, PA | 2 | Uranium | Base-load | 2,317 | ||||||||||||||||||||||
| Peach Bottom |
Mid-Atlantic | Delta, PA | 2 | 50 | Uranium | Base-load | 1,301 | (f) | ||||||||||||||||||||
| Salem |
Mid-Atlantic | |
Lower Alloways Creek Township, NJ |
|
2 | 42.59 | Uranium | Base-load | 1,005 | (f) | ||||||||||||||||||
| Calvert Cliffs |
Mid-Atlantic | Lusby, MD | 2 | 50.01 | Uranium | Base-load | 879 | (f)(g) | ||||||||||||||||||||
| Three Mile Island |
Mid-Atlantic | Middletown, PA | 1 | Uranium | Base-load | 837 | ||||||||||||||||||||||
| Oyster Creek |
Mid-Atlantic | Forked River, NJ | 1 | Uranium | Base-load | 625 | (e) | |||||||||||||||||||||
| Conowingo |
Mid-Atlantic | Darlington, MD | 11 | Hydroelectric | Base-load | 572 | ||||||||||||||||||||||
| Criterion |
Mid-Atlantic | Oakland, MD | 28 | Wind | Base-load | 70 | ||||||||||||||||||||||
| Fourmile |
Mid-Atlantic | Garrett County, MD | 16 | Wind | Base-load | 40 | ||||||||||||||||||||||
| Fair Wind |
Mid-Atlantic | Garrett County, MD | 12 | Wind | Base-load | 30 | ||||||||||||||||||||||
| Solar Maryland MC |
Mid-Atlantic | Various, MD | 16 | Solar | Base-load | 28 | ||||||||||||||||||||||
| Solar New Jersey 1 |
Mid-Atlantic | Various, NJ | 6 | Solar | Base-load | 18 | ||||||||||||||||||||||
| Solar Horizons |
Mid-Atlantic | Emmitsburg, MD | 1 | Solar | Base-load | 16 | ||||||||||||||||||||||
| Solar New Jersey 2 |
Mid-Atlantic | Various, NJ | 2 | Solar | Base-load | 11 | ||||||||||||||||||||||
| Solar Maryland |
Mid-Atlantic | Various, MD | 10 | Solar | Base-load | 9 | ||||||||||||||||||||||
| 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 | Solar | Base-load | 2 | ||||||||||||||||||||||
| 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 | 412 | ||||||||||||||||||||||
| 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 | ||||||||||||||||||||||
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Table of Contents
|
Station (a) |
Region |
Location |
No. of Units |
Percent Owned (b) |
Primary Fuel Type |
Primary Dispatch Type (c) |
Net Generation Capacity (MW) (d) |
|||||||||||||||||||||
| 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 Twp, NJ |
|
1 | 42.59 | Oil | Peaking | 16 | (f) | ||||||||||||||||||
| Pennsbury |
Mid-Atlantic | Morrisville, PA | 2 | Landfill Gas | Peaking | 6 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Total Mid-Atlantic |
11,624 | |||||||||||||||||||||||||||
| Whitetail |
ERCOT | Webb County, TX | 57 | Wind | Base-load | 91 | ||||||||||||||||||||||
| Sendero |
ERCOT | |
Jim Hogg and Zapata County, TX |
|
39 | Wind | Base-load | 78 | ||||||||||||||||||||
| Wolf Hollow 1, 2, 3 |
ERCOT | Granbury, TX | 3 | Gas | Intermediate | 705 | ||||||||||||||||||||||
| Mountain Creek 8 |
ERCOT | Dallas, TX | 1 | Gas | Intermediate | 568 | ||||||||||||||||||||||
| Colorado Bend |
ERCOT | Wharton, TX | 6 | Gas | Intermediate | 468 | ||||||||||||||||||||||
| Handley 3 |
ERCOT | Fort Worth, TX | 1 | Gas | Intermediate | 395 | ||||||||||||||||||||||
| Handley 4, 5 |
ERCOT | Fort Worth, TX | 2 | Gas | Peaking | 870 | ||||||||||||||||||||||
| Mountain Creek 6, 7 |
ERCOT | Dallas, TX | 2 | Gas | Peaking | 240 | ||||||||||||||||||||||
| LaPorte |
ERCOT | Laporte, TX | 4 | Gas | Peaking | 152 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Total ERCOT |
3,567 | |||||||||||||||||||||||||||
| Solar Massachusetts |
New England | Various, MA | 11 | Solar | Base-load | 5 | ||||||||||||||||||||||
| 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 | 3 | Solar | Base-load | 2 | ||||||||||||||||||||||
| Mystic 8, 9 |
New England | Charlestown, MA | 6 | Gas | Intermediate | 1,415 | ||||||||||||||||||||||
| 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/Gas | Peaking | 124 | ||||||||||||||||||||||
| Framingham |
New England | Framingham, MA | 3 | Oil | Peaking | 31 | ||||||||||||||||||||||
| Mystic Jet |
New England | Charlestown, MA | 1 | Oil | Peaking | 9 | ||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| Total New England |
2,204 | |||||||||||||||||||||||||||
| Nine Mile Point |
New York | Scriba, NY | 2 | 50.01 | Uranium | Base-load | 838 | (f)(g) | ||||||||||||||||||||
| 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 |
1,129 | |||||||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| AVSR |
Other | Lancaster, CA | 1 | Solar | Base-load | 242 | ||||||||||||||||||||||
| Shooting Star |
Other | Kiowa County, KS | 65 | Wind | Base-load | 104 | ||||||||||||||||||||||
| Exelon Wind 4 |
Other | Gruver, TX | 38 | Wind | Base-load | 80 | ||||||||||||||||||||||
| Bluestem |
Other | Beaver County, OK | 60 | 29 | Wind | Base-load | 57 | |||||||||||||||||||||
| Bluegrass Ridge |
Other | King City, MO | 27 | Wind | Base-load | 57 | ||||||||||||||||||||||
| Conception |
Other | Barnard, MO | 24 | Wind | Base-load | 50 | ||||||||||||||||||||||
| Cow Branch |
Other | Rock Port, MO | 24 | Wind | Base-load | 50 | ||||||||||||||||||||||
| Solar Arizona |
Other | Various, AZ | 127 | Solar | Base-load | 46 | ||||||||||||||||||||||
| Mountain Home |
Other | Glenns Ferry, ID | 20 | Wind | Base-load | 42 | ||||||||||||||||||||||
| High Mesa |
Other | Elmore Co., ID | 19 | Wind | Base-load | 40 | ||||||||||||||||||||||
| Echo 1 |
Other | Echo, OR | 21 | 99 | Wind | Base-load | 34 | (f) | ||||||||||||||||||||
| Sacramento PV Energy |
Other | Sacramento, CA | 4 | Solar | Base-load | 30 | ||||||||||||||||||||||
| Cassia |
Other | Buhl, ID | 14 | Wind | Base-load | 29 | ||||||||||||||||||||||
| Wildcat |
Other | Lovington, NM | 13 | Wind | Base-load | 27 | ||||||||||||||||||||||
| Sunnyside |
Other | Sunnyside, UT | 1 | 50 | Waste Coal | Base-load | 26 | (f)(h) | ||||||||||||||||||||
| Solar Arizona 2 |
Other | Various, AZ | 25 | Solar | Base-load | 23 | ||||||||||||||||||||||
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Table of Contents
|
Station (a) |
Region |
Location |
No. of Units |
Percent Owned (b) |
Primary Fuel Type |
Primary Dispatch Type (c) |
Net Generation Capacity (MW) (d) |
|||||||||||||||||||||
| California PV Energy |
Other | Various, CA | 53 | Solar | Base-load | 21 | ||||||||||||||||||||||
| Echo 2 |
Other | Echo, OR | 10 | Wind | Base-load | 20 | ||||||||||||||||||||||
| Tuana Springs |
Other | Hagerman, ID | 8 | Wind | Base-load | 17 | ||||||||||||||||||||||
| Greensburg |
Other | Greensburg, KS | 10 | Wind | Base-load | 13 | ||||||||||||||||||||||
| Echo 3 |
Other | Echo, OR | 6 | 99 | Wind | Base-load | 10 | (f) | ||||||||||||||||||||
| Exelon Wind 1 |
Other | Gruver, TX | 8 | Wind | Base-load | 10 | (i) | |||||||||||||||||||||
| Exelon Wind 2 |
Other | Gruver, TX | 8 | Wind | Base-load | 10 | (i) | |||||||||||||||||||||
| Exelon Wind 3 |
Other | Gruver, TX | 8 | Wind | Base-load | 10 | (i) | |||||||||||||||||||||
| 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 | ||||||||||||||||||||||
| High Plains |
Other | Panhandle, TX | 8 | 99.5 | Wind | Base-load | 10 | (f) | ||||||||||||||||||||
| Three Mile Canyon |
Other | Boardman, OR | 6 | Wind | Base-load | 10 | ||||||||||||||||||||||
| California PV Energy 2 |
Other | Various, CA | 31 | Solar | Base-load | 9 | ||||||||||||||||||||||
| Solar Georgia |
Other | Various, GA | 10 | Solar | Base-load | 8 | ||||||||||||||||||||||
| Outback Solar |
Other | Christmas Valley, OR | 1 | Solar | Base-load | 6 | ||||||||||||||||||||||
| 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 | Solar | Base-load | 4 | ||||||||||||||||||||||
| Solar California |
Other | Various, CA | 4 | Solar | Base-load | 3 | ||||||||||||||||||||||
| Solar Georgia 2 |
Other | Various, GA | 1 | Solar | Base-load | 1 | ||||||||||||||||||||||
| 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 |
2,046 | |||||||||||||||||||||||||||
| Total |
32,720 | |||||||||||||||||||||||||||
|
|
|
|||||||||||||||||||||||||||
| (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 has agreed to permanently cease generation operation at Oyster Creek by November 30, 2019. |
| (f) | Net generation capacity is stated at proportionate ownership share. |
| (g) | 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) | Generation sold its 50% interest in Sunnyside effective February 3, 2017 |
| (i) | Generation plans to retire and cease generation operations at the Exelon Wind 1, Exelon Wind 2 and Exelon Wind 3 units effective June 1, 2017. |
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 on Generation’s consolidated financial condition or results of operations.
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Table of Contents
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 higher voltage electric transmission lines owned and in service at December 31, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 765,000 |
90 | |
| 345,000 |
2,658 | |
| 138,000 |
2,208 |
ComEd’s electric distribution system includes 35,397 circuit miles of overhead lines and 31,049 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 on the consolidated financial condition or results of operations of ComEd.
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, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 500,000 |
188 (a) | |
| 230,000 |
549 | |
| 138,000 |
156 | |
| 69,000 |
200 |
| (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. |
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Table of Contents
PECO’s electric distribution system includes 12,963 circuit miles of overhead lines and 9,290 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2016:
| Pipeline Miles | ||||
| Transmission |
30 | |||
| Distribution |
6,871 | |||
| Service piping |
6,273 | |||
|
|
|
|||
| Total |
13,174 | |||
|
|
|
|||
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 157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 150 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO owns 31 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 on the consolidated financial condition or results of operations of PECO.
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, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 500,000 |
218 | |
| 230,000 |
331 | |
| 138,000 |
55 | |
| 115,000 |
709 |
BGE’s electric distribution system includes 9,443 circuit miles of overhead lines and 17,306 circuit miles of underground lines.
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Table of Contents
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2016:
| Pipeline Miles | ||||
| Transmission |
161 | |||
| Distribution |
7,239 | |||
| Service piping |
6,230 | |||
|
|
|
|||
| Total |
13,630 | |||
|
|
|
|||
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 on the consolidated financial condition or results of operations of BGE.
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, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 500,000 |
142 | |
| 230,000 |
774 | |
| 138,000 |
60 | |
| 115,000 |
38 |
Pepco’s electric distribution system includes approximately 4,100 circuit miles of overhead lines and 6,800 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.
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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 on the consolidated financial condition or results of operations of Pepco.
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, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 500,000 |
16 | |
| 230,000 |
470 | |
| 138,000 |
557 | |
| 69,000 |
576 |
DPL’s electric distribution system includes approximately 6,100 circuit miles of overhead lines and 6,100 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, 2016 :
| Pipeline Miles | ||||
| Transmission (a) |
7 | |||
| Distribution |
2,036 | |||
| Service Piping |
1,385 | |||
|
|
|
|||
| Total |
3,428 | |||
|
|
|
|||
| (a) | DPL has a 10% undivided interest in approximately 7 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 3,045 mmcf and an emergency sendout capability of 36,000 Mcf per 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 day.
First Mortgage and Insurance
The principal properties of PDL 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.
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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 on the consolidated financial condition or results of operations of DPL.
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, 2016 were as follows:
| Voltage (Volts) |
Circuit Miles | |
| 500,000 |
281 | |
| 230,000 |
234 | |
| 138,000 |
268 | |
| 69,000 |
652 |
ACE’s electric distribution system includes approximately 7,400 circuit miles of overhead lines and 2,900 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 on 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.
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| ITEM 3. | LEGAL PROCEEDINGS |
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding material lawsuits and proceedings, see Note 3—Regulatory Matters and Note 24—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.
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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. As of January 31, 2017, there were 926,589,614 shares of common stock outstanding and approximately 113,308 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:
| 2016 | 2015 | |||||||||||||||||||||||||||||||
| Fourth Quarter |
Third Quarter |
Second Quarter |
First Quarter |
Fourth Quarter |
Third Quarter |
Second Quarter |
First Quarter |
|||||||||||||||||||||||||
| High price |
$ | 36.36 | $ | 37.70 | $ | 36.37 | $ | 35.95 | $ | 31.37 | $ | 34.44 | $ | 34.98 | $ | 38.25 | ||||||||||||||||
| Low price |
29.82 | 32.86 | 33.18 | 26.26 | 25.09 | 28.41 | 31.28 | 31.71 | ||||||||||||||||||||||||
| Close |
35.49 | 33.29 | 36.36 | 35.86 | 27.77 | 29.70 | 31.42 | 33.61 | ||||||||||||||||||||||||
| Dividends |
0.318 | 0.318 | 0.318 | 0.310 | 0.310 | 0.310 | 0.310 | 0.310 | ||||||||||||||||||||||||
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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 2012 through 2016.
This performance chart assumes:
| • | $100 invested on December 31, 2011 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, | ||||||||||||
| 2011 | 2012 | 2013 | 2014 | 2015 | 2016 | |||||||
|
Exelon Corporation |
$100 | $70.69 | $65.11 | $88.14 | $66.01 | $84.36 | ||||||
|
S&P 500 |
$100 | $111.68 | $144.74 | $161.22 | $160.05 | $175.31 | ||||||
|
S&P Utilities |
$100 | $98.78 | $107.43 | $133.52 | $122.32 | $137.24 | ||||||
Generation
As of January 31, 2017, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2017, there were 127,017,157 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, 2017, in
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addition to Exelon, there were 299 record holders of ComEd common stock. There is no established market for shares of the common stock of ComEd.
PECO
As of January 31, 2017, 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, 2017, 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, 2017, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2017, 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, 2017, 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, 2017, 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
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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, 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 and notify the MDPSC that BGE’s equity ratio is at least 48% within five business days after dividend payment. There are no other limitations on BGE paying common stock dividends unless BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid.
Pepco is subject to certain dividend restrictions limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) 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.
DPL is subject to certain dividend restrictions imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay dividends, and (ii) 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.
ACE is subject to dividend restrictions imposed by: (i) state corporate laws, which impose limitations on the funds that can be used 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.
Exelon’s Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 dividend.
At December 31, 2016, Exelon had retained earnings of $12,030 million, including Generation’s undistributed earnings of $2,275 million, ComEd’s retained earnings of $987 million consisting of retained earnings appropriated for future dividends of $2,626 million, partially offset by $(1,639) million of unappropriated accumulated deficits, PECO’s retained earnings of $941 million, BGE’s retained earnings of $1,427 million, and PHI’s undistributed earnings of $(61) million.
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The following table sets forth Exelon’s quarterly cash dividends per share paid during 2016 and 2015:
| 2016 | 2015 | |||||||||||||||||||||||||||||||
| (per share) |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
||||||||||||||||||||||||
| Exelon |
$ | 0.318 | $ | 0.318 | $ | 0.318 | $ | 0.310 | $ | 0.310 | $ | 0.310 | $ | 0.310 | $ | 0.310 | ||||||||||||||||
The following table sets forth Generation’s and PHI’s quarterly distributions and ComEd’s, PECO’s, Pepco’s, DPL’s and ACE’s quarterly common dividend payments:
| 2016 | 2015 | |||||||||||||||||||||||||||||||
| (in millions) |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
4th Quarter |
3rd Quarter |
2nd Quarter |
1st Quarter |
||||||||||||||||||||||||
| Generation |
$ | 755 | $ | 56 | $ | 56 | $ | 55 | $ | 106 | $ | 106 | $ | 906 | $ | 1,356 | ||||||||||||||||
| ComEd |
94 | 92 | 92 | 91 | 73 | 76 | 75 | 75 | ||||||||||||||||||||||||
| PECO |
69 | 69 | 70 | 69 | 70 | 70 | 69 | 70 | ||||||||||||||||||||||||
| BGE |
45 | 44 | 45 | 45 | 42 | 39 | 41 | 36 | ||||||||||||||||||||||||
| PHI |
99 | 50 | 16 | 108 | 69 | 69 | 69 | 68 | ||||||||||||||||||||||||
| Pepco |
44 | 37 | 16 | 39 | 55 | 60 | 31 | — | ||||||||||||||||||||||||
| DPL |
15 | 1 | — | 38 | 12 | 18 | — | 62 | ||||||||||||||||||||||||
| ACE |
39 | 13 | — | 11 | — | — | — | 12 | ||||||||||||||||||||||||
First Quarter 2017 Dividend. On January 31, 2017, the Exelon Board of Directors declared a first quarter 2017 regular quarterly dividend of $0.3275 per share on Exelon’s common stock payable on March 10, 2017, to shareholders of record of Exelon at the end of the day on February 15, 2017.
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| ITEM 6. | SELECTED FINANCIAL DATA |
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) |
2016 (a) | 2015 | 2014 (b) | 2013 | 2012 (c) | |||||||||||||||
| Statement of Operations data: |
||||||||||||||||||||
| Operating revenues |
$ | 31,360 | $ | 29,447 | $ | 27,429 | $ | 24,888 | $ | 23,489 | ||||||||||
| Operating income |
3,112 | 4,409 | 3,096 | 3,669 | 2,373 | |||||||||||||||
| Net income |
1,204 | 2,250 | 1,820 | 1,729 | 1,171 | |||||||||||||||
| Net income attributable to common shareholders |
1,134 | 2,269 | 1,623 | 1,719 | 1,160 | |||||||||||||||
| Earnings per average common share (diluted): |
||||||||||||||||||||
| Net income |
$ | 1.22 | $ | 2.54 | $ | 1.88 | $ | 2.00 | $ | 1.42 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Dividends per common share |
$ | 1.26 | $ | 1.24 | $ | 1.24 | $ | 1.46 | $ | 2.10 | ||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| (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) | The 2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012. |
| December 31, | ||||||||||||||||||||
| (In millions) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Balance Sheet data: |
||||||||||||||||||||
| Current assets |
$ | 12,412 | $ | 15,334 | $ | 11,853 | $ | 9,562 | $ | 10,009 | ||||||||||
| Property, plant and equipment, net |
71,555 | 57,439 | 52,170 | 47,330 | 45,186 | |||||||||||||||
| Total assets |
114,904 | 95,384 | 86,416 | 79,243 | 78,350 | |||||||||||||||
| Current liabilities |
13,457 | 9,118 | 8,762 | 7,686 | 7,734 | |||||||||||||||
| Long-term debt, including long-term debt to financing trusts |
32,216 | 24,286 | 19,853 | 18,165 | 18,266 | |||||||||||||||
| Preferred securities of subsidiary |
— | — | — | — | 87 | |||||||||||||||
| Shareholders’ equity |
25,837 | 25,793 | 22,608 | 22,732 | 21,431 | |||||||||||||||
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) |
2016 | 2015 | 2014 (a) | 2013 | 2012 (b) | |||||||||||||||
| Statement of Operations data: |
||||||||||||||||||||
| Operating revenues |
$ | 17,751 | $ | 19,135 | $ | 17,393 | $ | 15,630 | $ | 14,437 | ||||||||||
| Operating income |
836 | 2,275 | 1,176 | 1,677 | 1,113 | |||||||||||||||
| Net income |
558 | 1,340 | 1,019 | 1,060 | 558 | |||||||||||||||
| (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) | The 2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012. |
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| December 31, | ||||||||||||||||||||
| (In millions) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Balance Sheet data: |
||||||||||||||||||||
| Current assets |
$ | 6,528 | $ | 6,342 | $ | 7,311 | $ | 5,964 | $ | 6,211 | ||||||||||
| Property, plant and equipment, net |
25,585 | 25,843 | 23,028 | 20,111 | 19,531 | |||||||||||||||
| Total assets |
46,974 | 46,529 | 44,951 | 40,700 | 40,648 | |||||||||||||||
| Current liabilities |
5,683 | 4,933 | 4,459 | 3,842 | 3,969 | |||||||||||||||
| Long-term debt, including long-term debt to affiliate |
8,124 | 8,869 | 7,582 | 7,111 | 7,422 | |||||||||||||||
| Member’s equity |
11,482 | 11,635 | 12,718 | 12,725 | 12,557 | |||||||||||||||
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) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Statement of Operations data: |
||||||||||||||||||||
| Operating revenues |
$ | 5,254 | $ | 4,905 | $ | 4,564 | $ | 4,464 | $ | 5,443 | ||||||||||
| Operating income |
1,205 | 1,017 | 980 | 954 | 886 | |||||||||||||||
| Net income |
378 | 426 | 408 | 249 | 379 | |||||||||||||||
| December 31, | ||||||||||||||||||||
| (In millions) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Balance Sheet data: |
||||||||||||||||||||
| Current assets |
$ | 1,554 | $ | 1,518 | $ | 1,723 | $ | 1,540 | $ | 1,692 | ||||||||||
| Property, plant and equipment, net |
19,335 | 17,502 | 15,793 | 14,666 | 13,826 | |||||||||||||||
| Total assets |
28,335 | 26,532 | 25,358 | 24,089 | 22,793 | |||||||||||||||
| Current liabilities |
2,938 | 2,766 | 1,923 | 2,032 | 1,655 | |||||||||||||||
| Long-term debt, including long-term debt to financing trusts |
6,813 | 6,049 | 5,870 | 5,235 | 5,492 | |||||||||||||||
| Shareholders’ equity |
8,725 | 8,243 | 7,907 | 7,528 | 7,323 | |||||||||||||||
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) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Statement of Operations data: |
||||||||||||||||||||
| Operating revenues |
$ | 2,994 | $ | 3,032 | $ | 3,094 | $ | 3,100 | $ | 3,186 | ||||||||||
| Operating income |
702 | 630 | 572 | 666 | 623 | |||||||||||||||
| Net income |
438 | 378 | 352 | 395 | 381 | |||||||||||||||
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| December 31, | ||||||||||||||||||||
| (In millions) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Balance Sheet data: |
||||||||||||||||||||
| Current assets |
$ | 757 | $ | 842 | $ | 645 | $ | 821 | $ | 1,054 | ||||||||||
| Property, plant and equipment, net |
7,565 | 7,141 | 6,801 | 6,384 | 6,078 | |||||||||||||||
| Total assets |
10,831 | 10,367 | 9,860 | 9,521 | 9,303 | |||||||||||||||
| Current liabilities |
727 | 944 | 653 | 889 | 1,158 | |||||||||||||||
| Long-term debt, including long-term debt to financing trusts |
2,764 | 2,464 | 2,416 | 2,120 | 1,821 | |||||||||||||||
| Preferred securities |
— | — | — | — | 87 | |||||||||||||||
| Shareholders’ equity |
3,415 | 3,236 | 3,121 | 3,065 | 2,982 | |||||||||||||||
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) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Statement of Operations data: |
||||||||||||||||||||
| Operating revenues |
$ | 3,233 | $ | 3,135 | $ | 3,165 | $ | 3,065 | $ | 2,735 | ||||||||||
| Operating income |
550 | 558 | 439 | 449 | 132 | |||||||||||||||
| Net income |
294 | 288 | 211 | 210 | 4 | |||||||||||||||
| December 31, | ||||||||||||||||||||
| (In millions) |
2016 | 2015 | 2014 | 2013 | 2012 | |||||||||||||||
| Balance Sheet data: |
&nbs | |||||||||||||||||||