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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
FORM 10-K
(Mark One)
| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
OR
| o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
| Commission | Registrant; State of Incorporation; | I.R.S. Employer | ||
| File Number | Address; and Telephone Number | Identification No. | ||
| 333-21011 | FIRSTENERGY CORP. | 34-1843785 | ||
| (An Ohio Corporation) | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 000-53742 | FIRSTENERGY SOLUTIONS CORP. | 31-1560186 | ||
| (An Ohio Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-2578 | OHIO EDISON COMPANY | 34-0437786 | ||
| (An Ohio Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-2323 | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | 34-0150020 | ||
| (An Ohio Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-3583 | THE TOLEDO EDISON COMPANY | 34-4375005 | ||
| (An Ohio Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-3141 | JERSEY CENTRAL POWER & LIGHT COMPANY | 21-0485010 | ||
| (A New Jersey Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-446 | METROPOLITAN EDISON COMPANY | 23-0870160 | ||
| (A Pennsylvania Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 | ||||
| 1-3522 | PENNSYLVANIA ELECTRIC COMPANY | 25-0718085 | ||
| (A Pennsylvania Corporation) | ||||
| c/o FirstEnergy Corp. | ||||
| 76 South Main Street | ||||
| Akron, OH 44308 | ||||
| Telephone (800)736-3402 |
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
| Name of Each Exchange | ||||
| Registrant | Title of Each Class | on Which Registered | ||
| FirstEnergy Corp. | Common Stock, $0.10 par value | New York Stock Exchange |
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
| Registrant | Title of Each Class | |
| Ohio Edison Company | Common Stock, no par value per share | |
| The Cleveland Electric Illuminating Company | Common Stock, no par value per share | |
| The Toledo Edison Company | Common Stock, $5.00 par value per share | |
| Jersey Central Power & Light Company | Common Stock, $10.00 par value per share | |
| Metropolitan Edison Company | Common Stock, no par value per share | |
| Pennsylvania Electric Company | Common Stock, $20.00 par value per share | |
| FirstEnergy Solutions Corp. | Common Stock, no par value per share |
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yesþ Noo | FirstEnergy Corp. | |
Yeso Noþ | FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company |
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Yeso Noþ | FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, FirstEnergy Solutions Corp. |
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yesþ Noo | FirstEnergy Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, FirstEnergy Solutions Corp. |
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).
Yesþ Noo | FirstEnergy Corp. | |
Yeso Noþ | FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company |
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 registrant’s 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.
Yeso Noþ Yesþ Noo | FirstEnergy Corp. FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company |
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ | FirstEnergy Corp. | |
Accelerated filero | N/A | |
Non-accelerated filer (do not check if a smaller reporting company)þ | FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company | |
Smaller reporting companyo | N/A |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Yeso Noþ | FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company |
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and ask price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter.
FirstEnergy Corp., $10,712,157,232 as of June 30, 2010; and for all other registrants, none.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date.
| OUTSTANDING | ||||
| CLASS | AS OF JANUARY 31, 2011 | |||
| FirstEnergy Corp., $0.10 par value | 304,835,407 | |||
| FirstEnergy Solutions Corp., no par value | 7 | |||
| Ohio Edison Company, no par value | 60 | |||
| The Cleveland Electric Illuminating Company, no par value | 67,930,743 | |||
| The Toledo Edison Company, $5 par value | 29,402,054 | |||
| Jersey Central Power & Light Company, $10 par value | 13,628,447 | |||
| Metropolitan Edison Company, no par value | 741,880 | |||
| Pennsylvania Electric Company, $20 par value | 4,427,577 | |||
FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company, and Pennsylvania Electric Company common stock.
Documents incorporated by reference (to the extent indicated herein):
| PART OF FORM 10-K INTO WHICH | ||
| DOCUMENT | DOCUMENT IS INCORPORATED | |
| Proxy Statement for 2011 Annual Meeting of Stockholders to be held May 17, 2011 | Part III |
This combined Form 10-K is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company. 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, except that information relating to any of the FirstEnergy subsidiary registrants is also attributed to FirstEnergy Corp.
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OMISSION OF CERTAIN INFORMATION
FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company, Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania 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 10-K with the reduced disclosure format specified in General Instruction I(2) to Form 10-K.
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Forward-Looking Statements:This Form 10-K includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
| • | The speed and nature of increased competition in the electric utility industry. |
| • | The impact of the regulatory process on the pending matters in the various states in which we do business. |
| • | Business and regulatory impacts from ATSI’s realignment into PJM Interconnection, L.L.C., economic or weather conditions affecting future sales and margins. |
| • | Changes in markets for energy services. |
| • | Changing energy and commodity market prices and availability. |
| • | Financial derivative reforms that could increase our liquidity needs and collateral costs, replacement power costs being higher than anticipated or inadequately hedged. |
| • | The continued ability of FirstEnergy’s regulated utilities to collect transition and other costs. |
| • | Operation and maintenance costs being higher than anticipated. |
| • | Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission and coal combustion residual regulations. |
| • | The potential impacts of any laws, rules or regulations that ultimately replace CAIR. |
| • | The uncertainty of the timing and amounts of the capital expenditures needed to resolve any NSR litigation or other potential similar regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units). |
| • | Adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC. |
| • | Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s transmission service charge appeal at the Commonwealth Court of Pennsylvania. |
| • | Any impact resulting from the receipt by Signal Peak of the Department of Labor’s notice of a potential pattern of violations at Bull Mountain Mine No.1. |
| • | The continuing availability of generating units and their ability to operate at or near full capacity. |
| • | The ability to comply with applicable state and federal reliability standards and energy efficiency mandates. |
| • | Changes in customers’ demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates. |
| • | The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives). |
| • | The ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins and the ability to experience growth in the distribution business. |
| • | The changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in amounts that are larger than currently anticipated. |
| • | The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital. |
| • | Changes in general economic conditions affecting the registrants. |
| • | The state of the capital and credit markets affecting the registrants. |
| • | Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees. |
| • | The continuing uncertainty of the national and regional economy and its impact on the registrants’ major industrial and commercial customers. |
| • | Issues concerning the soundness of financial institutions and counterparties with which the registrants do business. |
| • | The expected timing and likelihood of completion of the proposed merger with Allegheny, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect. |
| • | The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors. |
Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.
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GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
| ATSI | American Transmission Systems, Incorporated, owns and operates transmission facilities | |
| Beaver Valley | Beaver Valley Power Station | |
| CEI | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary | |
| FENOC | FirstEnergy Nuclear Operating Company, operates nuclear generating facilities | |
| FES | FirstEnergy Solutions Corp., provides energy-related products and services | |
| FESC | FirstEnergy Service Company, provides legal, financial and other corporate support services | |
| FEV | FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures | |
| FGCO | FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities | |
| FirstEnergy | FirstEnergy Corp., a public utility holding company | |
| Global Rail | A joint venture between FirstEnergy Ventures Corp. and WMB Loan Ventures II LLC, that owns coal transportation operations near Roundup, Montana | |
| GPU | GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001 | |
| JCP&L | Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary | |
| JCP&L Transition Funding | JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds | |
| JCP&L Transition Funding II | JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds | |
| Met-Ed | Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary | |
| NGC | FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities | |
| OE | Ohio Edison Company, an Ohio electric utility operating subsidiary | |
| Ohio Companies | CEI, OE and TE | |
| Penelec | Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary | |
| Penn | Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE | |
| Pennsylvania Companies | Met-Ed, Penelec and Penn | |
| PNBV | PNBV Capital Trust, a special purpose entity created by OE in 1996 | |
| Perry | Perry Nuclear Power Plant | |
| Shelf Registrants | FirstEnergy, OE, CEI, TE, JCP&L, Met-Ed and Penelec | |
| Shippingport | Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 | |
| Signal Peak | A joint venture between FirstEnergy Ventures Corp. and WMB Loan Ventures LLC, that owns mining and coal transportation operations near Roundup, Montana | |
| TE | The Toledo Edison Company, an Ohio electric utility operating subsidiary | |
| Utilities | OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec |
The following abbreviations and acronyms are used to identify frequently used terms in this report:
| AEP | American Electric Power Company, Inc. | |
| ALJ | Administrative Law Judge | |
| Allegheny | Allegheny Energy, Inc. is the parent holding company of Allegheny Supply, Monongahela Power Company, The Potomac Edison Company and West Penn Power Company | |
| AOCL | Accumulated Other Comprehensive Loss | |
| AQC | Air Quality Control | |
| ARO | Asset Retirement Obligation | |
| AS | Allegheny Energy Supply Company, LLC owns and operates non-nuclear generating facilities and purchases and sells energy and energy-related commodities | |
| BGS | Basic Generation Service | |
| CAA | Clean Air Act | |
| CAIR | Clean Air Interstate Rule | |
| CAMR | Clean Air Mercury Rule |
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GLOSSARY OF TERMS, Cont’d.
| CATR | Clean Air Transport Rule | |
| CBP | Competitive Bid Process | |
CO2 | Carbon dioxide | |
| CRDM | Control Rod Drive Mechanism | |
| CTC | Competitive Transition Charge | |
| DOE | United States Department of Energy | |
| DOJ | United States Department of Justice | |
| DCPD | Deferred Compensation Plan for Outside Directors | |
| DPA | Department of the Public Advocate, Division of Rate Counsel (New Jersey) | |
| ECAR | East Central Area Reliability Coordination Agreement | |
| EDCP | Executive Deferred Compensation Plan | |
| EE&C | Energy Efficiency and Conservation | |
| EMP | Energy Master Plan | |
| EPA | United States Environmental Protection Agency | |
| EPACT | Energy Policy Act of 2005 | |
| EPRI | Electric Power Research Institute | |
| ESOP | Employee Stock Ownership Plan | |
| ESP | Electric Security Plan | |
| FASB | Financial Accounting Standards Board | |
| FERC | Federal Energy Regulatory Commission | |
| FMB | First Mortgage Bond | |
| FPA | Federal Power Act | |
| FRR | Fixed Resource Requirement | |
| GAAP | Accounting Principles Generally Accepted in the United States | |
| GHG | Greenhouse Gases | |
| IFRS | International Financial Reporting Standards | |
| IRS | Internal Revenue Service | |
| ISO | Independent System Operators | |
| kV | Kilovolt | |
| KWH | Kilowatt-hours | |
| LED | Light-Emitting Diode | |
| LOC | Letter of Credit | |
| LTIP | Long-Term Incentive Plan | |
| MACT | Maximum Achievable Control Technology | |
| MDPSC | Maryland Public Service Commission | |
| MEIUG | Met-Ed Industrial Users Group | |
| MISO | Midwest Independent Transmission System Operator, Inc. | |
| Moody’s | Moody’s Investors Service, Inc. | |
| MRO | Market Rate Offer | |
| MTEP | MISO Regional Transmission Expansion Plan | |
| MW | Megawatts | |
| MWH | Megawatt-hours | |
| NAAQS | National Ambient Air Quality Standards | |
| NEIL | Nuclear Electric Insurance Limited | |
| NERC | North American Electric Reliability Corporation | |
| NJBPU | New Jersey Board of Public Utilities | |
| NNSR | Non-Attainment New Source Review | |
| NOAC | Northwest Ohio Aggregation Coalition | |
| NOPEC | Northeast Ohio Public Energy Council | |
| NOV | Notice of Violation | |
NOX | Nitrogen Oxide | |
| NRC | Nuclear Regulatory Commission | |
| NSR | New Source Review | |
| NUG | Non-Utility Generation | |
| NUGC | Non-Utility Generation Charge | |
| NYPSC | New York Public Service Commission | |
| NYSEG | New York State Electric and Gas Corporation | |
| OCC | Ohio Consumers’ Counsel | |
| OCI | Other Comprehensive Income | |
| OPEB | Other Post-Employment Benefits | |
| OVEC | Ohio Valley Electric Corporation |
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GLOSSARY OF TERMS, Cont’d.
| PCRB | Pollution Control Revenue Bond | |
| PICA | Pennsylvania Intergovernmental Cooperation Authority | |
| PJM | PJM Interconnection L. L. C. | |
| POLR | Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service | |
| PPUC | Pennsylvania Public Utility Commission | |
| PSA | Power Supply Agreement | |
| PSCWV | Public Service Commission of West Virginia | |
| PSD | Prevention of Significant Deterioration | |
| PUCO | Public Utilities Commission of Ohio | |
| QSPE | Qualifying Special-Purpose Entity | |
| RCP | Rate Certainty Plan | |
| RECs | Renewable Energy Credits | |
| RFP | Request for Proposal | |
| RTEP | Regional Transmission Expansion Plan | |
| RTC | Regulatory Transition Charge | |
| RTO | Regional Transmission Organization | |
| S&P | Standard & Poor’s Ratings Service | |
| SB221 | Ohio Amended Substitute Senate Bill 221 | |
| SBC | Societal Benefits Charge | |
| SEC | U.S. Securities and Exchange Commission | |
| SECA | Seams Elimination Cost Adjustment | |
| SIP | State Implementation Plan(s) Under the Clean Air Act | |
| SMIP | Smart Meter Implementation Plan | |
| SNCR | Selective Non-Catalytic Reduction | |
SO2 | Sulfur Dioxide | |
| SRECs | Solar Renewable Energy Credits | |
| TBC | Transition Bond Charge | |
| TMI-2 | Three Mile Island Unit 2 | |
| TSC | Transmission Service Charge | |
| VERO | Voluntary Enhanced Retirement Option | |
| VIE | Variable Interest Entity | |
| VSCC | Virginia State Corporation Commission |
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| EX-101 INSTANCE DOCUMENT | ||||||||
| EX-101 SCHEMA DOCUMENT | ||||||||
| EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
| EX-101 LABELS LINKBASE DOCUMENT | ||||||||
| EX-101 PRESENTATION LINKBASE DOCUMENT | ||||||||
| EX-101 DEFINITION LINKBASE DOCUMENT | ||||||||
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PART I
| ITEM 1. | BUSINESS |
Proposed Merger with Allegheny
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010 (Merger Agreement), with Element Merger Sub, Inc., a Maryland corporation, its wholly-owned subsidiary (Merger Sub) and Allegheny a Maryland corporation. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny with Allegheny continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny common stock, including grants of restricted common stock, would automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy, and Allegheny stockholders would own approximately 27% of the combined company. FirstEnergy would also assume all outstanding Allegheny debt.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, which was received on September 14, 2010; the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, which occurred on July 16, 2010. Approval of the merger was received from the VSCC on September 9, 2010. Approval from the FERC and from the PSCWV was received on December 16, 2010. Approval from the MDPSC was received on January 18, 2011. On January 7, 2011, we were notified by the DOJ that it had completed its review of the merger and closed its investigation. The proposed merger is also conditioned upon receipt of the approval of the PPUC. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny currently anticipate completing the merger in the first quarter of 2011. Although FirstEnergy and Allegheny believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
The Company
FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its eight principal electric utility operating subsidiaries: OE, CEI, TE, Penn, ATSI, JCP&L, Met-Ed and Penelec; and of its generating and marketing subsidiary, FES. FirstEnergy’s consolidated revenues are primarily derived from electric service provided by its utility operating subsidiaries and the revenues of its other principal subsidiary, FES. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., FirstEnergy Facilities Services Group, LLC, FirstEnergy Fiber Holdings Corp., GPU Power, Inc., GPU Nuclear, Inc., MARBEL Energy Corporation and FESC.
FES was organized under the laws of the State of Ohio in 1997. FES provides energy-related products and services to wholesale and retail customers. FES also owns and operates, through its subsidiary, FGCO, FirstEnergy’s fossil and hydroelectric generating facilities and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, organized under the laws of the State of Ohio in 1998, operates and maintains NGC’s nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, as well as the output relating to leasehold interests of the Ohio Companies in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.
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FirstEnergy’s generating portfolio includes 13,436 MW of diversified capacity (FES — 13,236 MW and JCP&L — 200 MW). Within FES’ portfolio, approximately 7,157 MW, or 54.1%, consist of coal-fired capacity; 3,991 MW, or 30.2%, consist of nuclear capacity; 1,151 MW, or 8.7%, consist of oil and natural gas peaking units; 451 MW, or 3.4%, consist of hydroelectric capacity, 376 MW, or 2.8%, are from wind facilities; and 110 MW, or 0.8%, consist of capacity from FGCO’s current 4.85% entitlement to the generation output owned by the OVEC. FirstEnergy’s nuclear and non-nuclear facilities are operated by FENOC and FGCO, respectively, and, except for portions of certain facilities that are subject to the sale and leaseback arrangements with non-affiliates referred to above for which the corresponding output is available to FES through power sale agreements, are all owned directly by NGC and FGCO, respectively. The FES generating assets are concentrated primarily in Ohio and Pennsylvania. All FES units are currently dedicated to MISO except Beaver Valley and Seneca Pumped Storage Plant, which are designated as a PJM resource. Additionally, see FERC Matters for RTO Realignment.
FES, FGCO and NGC comply with the regulations, orders, policies and practices prescribed by the SEC and the FERC. In addition, NGC and FENOC comply with the regulations, orders, policies and practices prescribed by the NRC.
The Utilities’ combined service areas encompass approximately 36,100 square miles in Ohio, New Jersey and Pennsylvania. The areas they serve have a combined population of approximately 11.3 million.
OE was organized under the laws of the State of Ohio in 1930 and owns property and does business as an electric public utility in that state. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio. The area it serves has a population of approximately 2.8 million. OE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
OE owns all of Penn’s outstanding common stock. Penn was organized under the laws of the Commonwealth of Pennsylvania in 1930 and owns property and does business as an electric public utility in that state. Penn is also authorized to do business in the State of Ohio (see Item 2 — Properties). Penn furnishes electric service to communities in 1,100 square miles of western Pennsylvania. The area it serves has a population of approximately 0.4 million. Penn complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
CEI was organized under the laws of the State of Ohio in 1892 and does business as an electric public utility in that state. CEI engages in the distribution and sale of electric energy in an area of approximately 1,600 square miles in northeastern Ohio. The area it serves has a population of approximately 1.8 million. CEI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
TE was organized under the laws of the State of Ohio in 1901 and does business as an electric public utility in that state. TE engages in the distribution and sale of electric energy in an area of approximately 2,300 square miles in northwestern Ohio. The area it serves has a population of approximately 0.8 million. TE complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PUCO.
ATSI was organized under the laws of the State of Ohio in 1998. ATSI owns transmission assets that were formerly owned by the Ohio Companies and Penn. ATSI owns major, high-voltage transmission facilities, which consist of approximately 5,821 pole miles of transmission lines with nominal voltages of 345 kV, 138 kV and 69 kV. Effective October 1, 2003, ATSI transferred operational control of its transmission facilities to MISO. On December 17, 2009, the FERC authorized ATSI to transfer operational control of its facilities to PJM. As described below in FERC Matters the transfer is scheduled to occur on June 1, 2011. ATSI plans, operates, and maintains its transmission system in accordance with NERC reliability standards, and applicable regulatory requirements to ensure reliable service to customers. Additionally, see FERC Matters for RTO Realignment. ATSI complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and applicable state regulatory authorities.
JCP&L was organized under the laws of the State of New Jersey in 1925 and owns property and does business as an electric public utility in that state. JCP&L provides transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.6 million. JCP&L complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and the NJBPU.
Met-Ed was organized under the laws of the Commonwealth of Pennsylvania in 1922 and owns property and does business as an electric public utility in that state. Met-Ed provides transmission and distribution services in 3,300 square miles of eastern and south central Pennsylvania. The area it serves has a population of approximately 1.3 million. Met-Ed complies with the regulations, orders, policies and practices prescribed by the SEC, FERC and PPUC.
Penelec was organized under the laws of the Commonwealth of Pennsylvania in 1919 and owns property and does business as an electric public utility in that state. Penelec provides transmission and distribution services in 17,600 square miles of western, northern and south central Pennsylvania. The area it serves has a population of approximately 1.6 million. Penelec, as lessee of the property of its subsidiary, The Waverly Electric Light & Power Company, also serves customers in Waverly, New York and its vicinity. Penelec complies with the regulations, orders, policies and practices prescribed by the SEC, FERC, NYPSC and PPUC, as applicable.
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FESC provides legal, financial and other corporate support services to affiliated FirstEnergy companies.
Reference is made to Note 15, Segment Information, of the Notes to Consolidated Financial Statements contained in Item 8 for information regarding FirstEnergy’s reportable segments.
Utility Regulation
State Regulation
Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the state in which each company operates — in Ohio by the PUCO, in New Jersey by the NJBPU and in Pennsylvania by the PPUC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
As a competitive retail electric supplier serving retail customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan, and Illinois, FES is subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES and its public utility affiliates. In addition, if FES or any of its subsidiaries were to engage in the construction of significant new generation facilities, they would also be subject to state siting authority.
Federal Regulation
With respect to their wholesale and interstate electric operations and rates, the Utilities, ATSI, FES, FGCO and NGC are subject to regulation by the FERC. Under the FPA, the FERC regulates rates for interstate sales at wholesale, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. The FERC regulations require ATSI, Met-Ed, JCP&L and Penelec to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission service over ATSI’s facilities is provided by MISO under its open access transmission tariff although as explained herein effective June 1, 2011 transmission service over ATSI’s facilities will be provided pursuant to PJM’s open access transmission tariff. Transmission service over Met-Ed’s, JCP&L’s and Penelec’s facilities is provided by PJM under its open access transmission tariff. The FERC also regulates unbundled transmission service to retail customers. Additionally, see FERC Matters for RTO Realignment.
The FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon a showing that the seller cannot exert market power in generation or transmission. FES, FGCO and NGC have been authorized by the FERC to sell wholesale power in interstate commerce and have a market-based tariff on file with the FERC. By virtue of this tariff and authority to sell wholesale power, each company is regulated as a public utility under the FPA. However, consistent with its historical practice, the FERC has granted FES, FGCO and NGC a waiver from most of the reporting, record-keeping and accounting requirements that typically apply to traditional public utilities. Along with market-based rate authority, the FERC also granted FES, FGCO and NGC blanket authority to issue securities and assume liabilities under Section 204 of the FPA. As a condition to selling electricity on a wholesale basis at market-based rates, FES, FGCO and NGC, like all other entities granted market-based rate authority, must file electronic quarterly reports with the FERC, listing their sales transactions for the prior quarter.
The nuclear generating facilities owned and leased by NGC are subject to extensive regulation by the NRC. 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. 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 licenses. FENOC is the licensee for the operating nuclear plants and has direct compliance responsibility for NRC matters. FES controls the economic dispatch of NGC’s plants. See Nuclear Regulation below.
Regulatory Accounting
The Utilities and ATSI recognize, as regulatory assets, costs which the FERC, PUCO, PPUC and NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. All regulatory assets are expected to be recovered from customers under the Utilities’ respective transition and regulatory plans. Based on those plans, the Utilities and ATSI continue to bill and collect cost-based rates for their transmission and distribution services, which remain regulated; accordingly, it is appropriate that the Utilities and ATSI continue the application of regulatory accounting to those operations.
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FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to its operating utilities since their rates:
| • | are established by a third-party regulator with the authority to set rates that bind customers; | ||
| • | are cost-based; and | ||
| • | can be charged to and collected from customers. |
An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense (regulatory assets) if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded net regulatory assets are removed from the balance sheet in accordance with GAAP.
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Utilities’ respective state regulatory plans. These provisions include:
| • | restructuring the electric generation business and allowing the Utilities’ customers to select a competitive electric generation supplier other than the Utilities; | ||
| • | establishing or defining the POLR obligations to customers in the Utilities’ service areas; | ||
| • | providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; | ||
| • | itemizing (unbundling) the price of electricity into its component elements — including generation, transmission, distribution and stranded costs recovery charges; | ||
| • | continuing regulation of the Utilities’ transmission and distribution systems; and | ||
| • | requiring corporate separation of regulated and unregulated business activities. |
Reliability Initiatives
In 2005, Congress amended the FPA to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC and ATSI. The NERC, as the ERO, is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirstperformed a routine compliance audit of FirstEnergy’s bulk-power system within the Midwest ISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirstperformed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards. In May 2010, ReliabilityFirstperformed a routine compliance audit of FirstEnergy’s bulk-power system in the Midwest ISO region and, subject to certain nonmaterial items, found it to be in compliance with the audited reliability standards. FirstEnergy’s PJM facilities are next due for the periodic audit by ReliabilityFirstin 2011.
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Ohio Regulatory Matters
The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. On February 2, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing filed both by the Ohio Companies and by the other party.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The PUCO approved the new ESP on August 25, 2010 with certain modifications. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; a load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to pay certain costs related to the companies’ integration into PJM, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, established a $12 million fund to assist low income customers over the term of the ESP, and agreed to additional energy efficiency benefits. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the integration into PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. On February 9, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO, which is delaying the launch of the programs described in the plan. As a result, the Ohio Companies filed on January 11, 2011, a request for amendment of OE’s 2010 energy efficiency and peak demand reduction benchmarks to levels actually achieved in 2010. Because the Commission indicated that it would revise all of the Ohio Companies’ 2010, 2011, and 2012 benchmarks when addressing the Ohio Companies’ three year portfolio plan, and an order has yet to be issued on that plan, CEI and TE also requested a waiver of their respective yet-to-be defined 2010 energy efficiency benchmarks if and only to the degree one is deemed necessary to bring these companies into compliance with their 2010 energy efficiency obligations. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty.
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Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011. As a result of this RFP, contracts were executed in August 2010. On January 11, 2011, the Ohio Companies filed an application with the PUCO seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio due to the insufficient quantity of solar energy resources reasonably available in the market. The PUCO has not yet ruled on that application.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010, and the proceeding remains open. The hearing in the matter is set to commence on February 16, 2011.
Pennsylvania Regulatory Matters
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $252.7 million ($188.0 million for Met-Ed and $64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. The argument before the Commonwealth Court,en banc, was held on December 8, 2010.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. On August 12, 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan on November 6, 2009. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
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Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC on August 14, 2009. This plan proposed a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
New Jersey Regulatory Matters
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2010, the accumulated deferred cost balance was a credit of approximately $37 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. On February 10, 2011, the NJBPU approved a stipulation which allows the change in rates to become effective March 1, 2011.
On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). This matter is currently pending before the NJBPU.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.
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FERC Matters
Rates for Transmission Service Between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. On May 21, 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC on November 23, 2010, and the relevant payments made. Rehearings remain pending in this proceeding.
PJM Transmission Rate
On April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings”— meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act by May 31, 2011.
RTO Realignment
On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s withdrawal from MISO and integration into PJM. This move, which is expected to be effective on June 1, 2011, allows FirstEnergy to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The realignment will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a FRR Plan to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.
FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements. On August 25, 2010, the PUCO issued an order in the 2010 ESP Case approving a settlement that, among other things, called for the PUCO to withdraw its opposition to the RTO consolidation. In addition, the order approved a wholesale procurement process, and certain “retail choice” policies, that reflected ATSI’s entry into PJM on June 1, 2011.
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On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. Additional FERC proceedings are either pending or expected in which the amount of exit fees, transmission cost allocations, and costs associated with long term firm transmission rights payable by the ATSI zone upon its withdrawal from the Midwest ISO will be determined. In addition, certain parties may protest other aspects of ATSI’s integration into PJM, and certain of these matters remain outstanding and will be resolved in future FERC proceedings. The outcome of these proceedings cannot be predicted.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—are a class of MTEP projects. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $11 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
On September 10, 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVP projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
On December 16, 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attach prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, the Company argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time.
Sales to Affiliates
FES has received authorization from FERC to make wholesale power sales to the Utilities. FES actively participates in auctions conducted by or on behalf of the Utilities to obtain the power and related services necessary to meet the Utilities’ POLR obligations. Because of the merger with FirstEnergy, AS is considered an affiliate of the Utilities for purposes of FERC’s affiliate restriction regulations. This requires AS to obtain prior FERC authorization to make sales to the Utilities when it successfully participates in the Utilities’ POLR auctions.
FES currently supplies the Ohio Companies with a portion of their capacity, energy, ancillary services and transmission under a Master SSO Supply Agreement for a two-year period ending May 31, 2011. FES won 51 tranches in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International on May 13-14, 2009. Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009. FES also supplies power used by Constellation to serve an additional five tranches. As a result of these arrangements, FES serves 77 tranches, or 77% of the POLR load of the Ohio Companies until May 31, 2011.
On October 20, 2010, FES participated in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International, for the following periods: June 1, 2011 through May 31, 2012; June 1, 2011, through May 31, 2013; and June 1, 2010 through May 31, 2014. The Ohio Companies offered 17, 17, and 16 tranches for these periods, respectively. FES won 10, 7, and 3 tranches, respectively, for these periods. On January 25, 2011, the Ohio Companies conducted a second auction offering the same product for identical time periods. FES won 3, 0, and 3 tranches, respectively, for these periods. FES entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services, and congestion costs to the Ohio Companies for the tranches won. Under the ESP in effect for these time periods, the Ohio Companies are responsible for payment of noncontrollable transmission costs billed by PJM for POLR service.
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On October 18, 2010, FES participated in a descending clock auction for POLR service administered by both Met-Ed and Penelec and their consultant, National Economic Research Associates (NERA) for the following tranche products and delivery periods: Residential 5-month, Residential 24-month, Commercial 5-month, Commercial 12-month and Industrial 12-month. All 5-month delivery periods are from January 1, 2011 through May 31, 2011, all 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 7 Residential 5-month tranches, 4 Residential 24-month tranches, 6 Commercial 5-month tranches, 6 Commercial 12-month tranches and 1 Industrial tranche while Penelec offered 5 Residential 5-month tranches, 3 Residential 24-month tranches, 5 Commercial 5-month tranches, 5 Commercial 12-month tranches and 1 Industrial tranche.
For Met-Ed offerings, FES won 4 Residential 5-month tranches, 2 Residential 24-month tranches, 1 Commercial 5-month tranche, 1 Commercial 12-month tranche and zero Industrial tranches. For Penelec offerings, FES won 1 Residential 5-month tranche, 1 Residential 24-month tranche, zero Commercial 5-month tranches, zero Commercial 12-month tranches and zero Industrial tranches. FES entered into separate Supplier Master Agreements (SMA) to provide capacity, energy, ancillary services, and congestion costs with Met-Ed and Penelec for each product won. Under the terms and conditions of the SMA, Met-Ed and Penelec are responsible for payment of noncontrollable transmission costs billed by PJM.
On January 18 to 20, 2011 FES participated in a descending clock auction for POLR service administered by Met-Ed, Penelec, and Penn Power and their consultant, NERA for the following tranche products and delivery periods: Residential 12-month, Residential 24-month, Commercial 12-month and Industrial 12-month. All 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 3 Residential 12-month tranches, 4 Residential 24-month tranches, 6 Commercial 12-month tranches and 11 Industrial tranches. Penelec offered 3 Residential 12-month tranches, 2 Residential 24-month tranches, 5 Commercial 12-month tranches and 11 Industrial tranches. Penn Power offered 2 Residential 12-month tranches, 1 Residential 24-month tranche, 3 Commercial 12-month tranches and 3 Industrial tranches.
For Met-Ed offerings, FES won 1 Commercial 12-month tranche and zero for the remaining products. For Penelec and Penn Power offerings, FES won no tranches. FES entered into a SMA to provide capacity, energy, ancillary services, and congestion costs with Met-Ed for the product won. Under the terms and conditions of the SMA, Met-Ed is responsible for payment of noncontrollable transmission costs billed by PJM.
Capital Requirements
Our capital spending for 2011 is expected to be approximately $1.4 billion (excluding nuclear fuel). For 2012 and 2013 we anticipate average annual baseline capital expenditures of approximately $1.2 billion — that excludes currently unplanned investment opportunities or future mandated spending. Baseline capital initiatives promote reliability, improve operations, and support current environmental and energy efficiency directives. Our capital investments for additional nuclear fuel are expected to be $133 million, $300 million and $183 million in 2011, 2012 and 2013, respectively.
Anticipated capital expenditures for the Utilities, FES and FirstEnergy’s other subsidiaries for 2011, excluding nuclear fuel, are shown in the following table. Such costs include expenditures for the betterment of existing facilities and for the completion of generating capacity, construction, transmission lines, distribution lines, substations and other assets.
| Capital | ||||||||
| 2010 | Expenditures | |||||||
| Actual(1) | Forecast 2011 | |||||||
| (In millions) | ||||||||
| OE | $ | 138 | $ | 127 | ||||
| Penn | 26 | 20 | ||||||
| CEI | 113 | 117 | ||||||
| TE | 46 | 37 | ||||||
| JCP&L | 190 | 181 | ||||||
| Met-Ed | 106 | 89 | ||||||
| Penelec | 135 | 121 | ||||||
| ATSI | 67 | 60 | ||||||
| FGCO | 581 | 215 | ||||||
| NGC | 333 | 393 | ||||||
| Other subsidiaries | 78 | 60 | ||||||
| Total | $ | 1,813 | $ | 1,420 | ||||
| (1) | Excludes nuclear fuel. |
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During the 2011-2015 period, maturities of, and sinking fund requirements for, long-term debt of FirstEnergy and its subsidiaries are:
| Long-Term Debt Redemption Schedule | ||||||||||||
| 2011 | 2012-2015 | Total | ||||||||||
| (In millions) | ||||||||||||
| FirstEnergy | $ | 250 | $ | — | $ | 250 | ||||||
| FES | 163 | 692 | 855 | |||||||||
| OE | — | 150 | 150 | |||||||||
| Penn | 1 | 4 | 5 | |||||||||
| CEI | 20 | 396 | 416 | |||||||||
| JCP&L | 32 | 149 | 181 | |||||||||
| Met-Ed | — | 400 | 400 | |||||||||
| Penelec | — | 150 | 150 | |||||||||
Other(1) | (21 | ) | 229 | 208 | ||||||||
| Total | $ | 445 | $ | 2,170 | $ | 2,615 | ||||||
| (1) | Includes elimination of certain intercompany debt. |
The following tables display consolidated operating lease commitments as of December 31, 2010.
| Lease | Capital | |||||||||||
| Operating Leases | Payments | Trust | Net | |||||||||
| (In millions) | ||||||||||||
| 2011 | $ | 329 | $ | 116 | $ | 213 | ||||||
| 2012 | 365 | 125 | 240 | |||||||||
| 2013 | 367 | 130 | 237 | |||||||||
| 2014 | 363 | 131 | 232 | |||||||||
| 2015 | 365 | 91 | 274 | |||||||||
| Years thereafter | 2,150 | 32 | 2,118 | |||||||||
| Total minimum lease payments | $ | 3,939 | $ | 625 | $ | 3,314 | ||||||
| Operating Leases | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| 2011 | $ | 192 | $ | 146 | $ | 4 | $ | 64 | $ | 6 | $ | 4 | $ | 3 | ||||||||||||||
| 2012 | 230 | 147 | 3 | 64 | 5 | 4 | 3 | |||||||||||||||||||||
| 2013 | 236 | 147 | 3 | 64 | 5 | 4 | 3 | |||||||||||||||||||||
| 2014 | 234 | 146 | 3 | 64 | 5 | 4 | 2 | |||||||||||||||||||||
| 2015 | 238 | 146 | 3 | 64 | 4 | 4 | 2 | |||||||||||||||||||||
| Years thereafter | 1,895 | 166 | 6 | 79 | 48 | 40 | 23 | |||||||||||||||||||||
| Total minimum lease payments | $ | 3,025 | $ | 898 | $ | 22 | $ | 399 | $ | 73 | $ | 60 | $ | 36 | ||||||||||||||
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2011, FirstEnergy expects to satisfy these requirements with internal cash from operations — external funds may also be raised in the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
FirstEnergy had approximately $700 million of short-term indebtedness as of December 31, 2010, comprised of borrowings under the $2.75 billion revolving line of credit described below. Total short-term bank lines of committed credit to FirstEnergy, FES and the Utilities as of January 31, 2011 were approximately $3.2 billion.
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FirstEnergy, along with certain of its subsidiaries, are party to a $2.75 billion five-year revolving credit facility. FirstEnergy has the ability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations. The annual facility fee is 0.125%.
As of January 31, 2011, FES had a $100 million term loan in addition to a $1 billion credit limit associated with FirstEnergy’s $2.75 billion revolving credit facility. Also, an aggregate of $395 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy’s available liquidity as of January 31, 2011, is described in the following table.
| Available | ||||||||||||||
| Company | Type | Maturity | Commitment | Liquidity | ||||||||||
| (In millions) | ||||||||||||||
FirstEnergy(1) | Revolving | Aug. 2012 | $ | 2,750 | $ | 2,245 | ||||||||
| FES | Term loan | Mar. 2011 | 100 | — | ||||||||||
| Ohio and Pennsylvania Companies | Receivables financing | Various | (2) | 395 | 237 | |||||||||
| Subtotal | $ | 3,245 | $ | 2,482 | ||||||||||
| Cash | — | 668 | ||||||||||||
| Total | $ | 3,245 | $ | 3,150 | ||||||||||
| (1) | FirstEnergy Corp. and subsidiary borrowers. | |
| (2) | Ohio — $250 million matures March 30, 2011; Pennsylvania — $145 million matures June 17, 2011 with optional extension terms. |
FirstEnergy’s primary source of cash for continuing operations as a holding company is cash from the operations of its subsidiaries. During 2010, the holding company received $850 million of cash dividends on common stock from its subsidiaries and paid $670 million in cash dividends to common shareholders.
As of December 31, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.4 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $124 million and $26 million, respectively, as of December 31, 2010. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $394 million and $343 million, respectively, under provisions of their senior note indentures as of December 31, 2010.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of December 31, 2010, FGCO had the capability to issue $1.7 billion of additional FMBs under the terms of that indenture. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $695 million of additional FMBs as of December 31, 2010.
To the extent that coverage requirements or market conditions restrict the subsidiaries’ abilities to issue desired amounts of FMBs or preferred stock, they may seek other methods of financing. Such financings could include the sale of preferred and/or preference stock or of such other types of securities as might be authorized by applicable regulatory authorities which would not otherwise be sold and could result in annual interest charges and/or dividend requirements in excess of those that would otherwise be incurred.
On September 22, 2008, the Shelf Registrants filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants may utilize the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities.
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Nuclear Operating Licenses
On August 27, 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. On December 27 and 28, 2010, a group of petitioners filed a request for hearing, contending that FENOC failed to adequately consider wind or solar generation, or some combination thereof, as an alternative to license extension at Davis Besse. They further argued FENOC had failed to adequately assess the cost of a severe accident at Davis Besse. FENOC and the NRC staff responded to this pleading on January 21, 2011, demonstrating that none of the petitioners’ arguments were admissible contentions under the National Environmental Policy Act or NRC regulations. An Atomic Safety and Licensing Board panel is expected to determine whether a hearing is necessary in this matter.
The following table summarizes the current operating license expiration dates for FES’ nuclear facilities in service.
| Current License | ||||||||
| Station | In-Service Date | Expiration | ||||||
| Beaver Valley Unit 1 | 1976 | 2036 | ||||||
| Beaver Valley Unit 2 | 1987 | 2047 | ||||||
| Perry | 1986 | 2026 | ||||||
| Davis-Besse | 1977 | 2017 | ||||||
Nuclear Regulation
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2010, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and its effects on particular businesses and the economy could also affect the values of the nuclear decommissioning trusts. The NRC recently issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of FirstEnergy’s nuclear facilities. As a result, FirstEnergy’s decommissioning funding obligations are expected to increase. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.
Nuclear Insurance
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion (OE-$120 million, NGC-$1.22 billion, TE-$64 million) for replacement power costs incurred during an outage after an initial 26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $9 million (OE-$1 million, NGC-$8 million, and TE-less than $1 million).
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FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $61 million (OE-$5 million, NGC-$52 million, TE-$2 million, Met Ed, Penelec, and JCP&L-less than $1 million each) during a policy year.
FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
Hydro Relicensing
Yards Creek
The Yards Creek Pumped Storage Project is a 400 MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided 50% interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. Authorization to operate the project is by a license issued by the FERC. The existing license expires on February 28, 2013.
In February 2011 FirstEnergy and PSEG filed a joint application with FERC to renew the license for an additional fifty years. The companies are pursuing relicensure through FERC’s Integrated License Application Process (ILP). Under the ILP process FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunity for intervention and protests by affected third parties. FERC may hold hearings during the 2-year ILP licensure period. FirstEnergy expects FERC to issue the new license within the remaining portion of the 2-year ILP period. To the extent, however that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca
The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania. FGCO owns and operates the project. The current FERC license was issued on December 1, 1965, and will expire on November 30, 2015. FGCO expects to file its new license application on or before November 30, 2013.
On November 23, 2010, FGCO filed its notice of intent to relicense and pre-application document (PAD). On November 30, 2010, the Seneca Nation of Indians (Salamanca, NY) filed a competing notice of intent to file a new license application and PAD. On January 28, 2011, FERC issued a notice of the competing notices of intent and PADs; commencement of prefiling process and scoping; request for comments on the PADs; and identification of issues and associated study requests.
FERC’s ILP provides a 5 year period for preparation, submission and adjudication of the licenses. The first part is a 3-year period during which each of FirstEnergy and the Seneca Nation are to collect the information and conduct the studies necessary to support license applications. The second part is the same as the licensing process described above for Yards Creek.
Section 15 of the Federal Power Act provides that when there are competing license applications, insignificant differences between competing applications are not determinative and shall not result in transfer of the license for the project. Based on the facts and the law, FirstEnergy believes it qualifies for this “incumbent preference”. The timetable for a FERC decision cannot be predicted at this time.
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Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
The Sammis, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NOx and SO2 emissions through the installation of pollution control devices or repowering. OE and Penn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement.
In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in those three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy.
In January 2009, the EPA issued a NOV to GenOn alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986 and also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that “modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. In January, 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on alleged “modifications” at the Homer City Power Station between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the State of New York intervened and have filed a separate complaint regarding the Homer City Station. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy Westside, Inc. is under dispute and Penelec is unable to predict the outcome of this matter.
In January 2011, a complaint was filed against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’s air emissions. The complaint was also filed against the former co-owner, NYSEG and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. The complaint also seeks certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint.
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In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR, and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the CATR to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management continues to assess the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. In August 2010, for example, management decided to idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. On January 20, 2011, the U.S. District Court for the District of Columbia denied a motion by the EPA for an extension of the deadline to issue final rules, ordering the EPA to issue such rules by February 21, 2011. The EPA also entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
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In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. On December 6, 2010, the U.S. Supreme Court granted a writ of certiorari to the Second Circuit inConnecticut v. AEP. Briefing and oral argument are expected to be completed in early 2011 and a decision issued in or around June 2011. While FirstEnergy is not a party to this litigation, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy’s operations.
The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’s cooling water system). The EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On November 19, 2010, the Ohio EPA issued a permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
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In June 2008, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of December 31, 2010, based on estimates of the total costs of cleanup, the Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $32 million) have been accrued through December 31, 2010. Included in the total are accrued liabilities of approximately $64 million for environmental remediation of former MGPs and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Fuel Supply
FES currently has long-term coal contracts with various terms to acquire approximately 19.2 million tons of coal for the year 2011, approximately 116% of its 2011 coal requirements of 16.6 million tons. This contract coal is produced primarily from mines located in Ohio, Pennsylvania, West Virginia, Montana and Wyoming. The contracts expire at various times through December 31, 2030. FES has contracted sufficient storage to manage the coal inventory should that be necessary. See “Environmental Matters” for factors pertaining to meeting environmental regulations affecting coal-fired generating units.
In July 2008, FEV entered into a joint venture with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, to acquire a majority stake in the Bull Mountain Mine Operations, now called Signal Peak, near Roundup, Montana. This joint venture is part of FirstEnergy’s strategy to secure high-quality fuel supplies at attractive prices to maximize the capacity of its fossil generating plants. In a related transaction, FGCO entered into a 15-year agreement to purchase up to 10 million tons of bituminous western coal annually from the mine. FirstEnergy also entered into agreements with the rail carriers associated with transporting coal from the mine to its generating stations, and began taking delivery of the coal in late 2009. The joint venture has the right to resell Signal Peak coal tonnage not used at FirstEnergy facilities and has call rights on such coal above certain levels.
FirstEnergy has contracts for all uranium requirements through 2012 and a portion of uranium material requirements through 2024. Conversion services contracts fully cover requirements through 2011 and partially fill requirements through 2024. Enrichment services are contracted for essentially all of the enrichment requirements for nuclear fuel through 2020. A portion of enrichment requirements is also contracted for through 2024. Fabrication services for fuel assemblies are contracted for both Beaver Valley units and Davis-Besse through 2013 and through the current operating license period for Perry. The Davis-Besse fabrication contract also has an extension provision for services for additional consecutive reload batches through the current operating license period. In addition to the existing commitments, FirstEnergy intends to make additional arrangements for the supply of uranium and for the subsequent conversion, enrichment, fabrication, and waste disposal services.
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On-site spent fuel storage facilities are expected to be adequate for Beaver Valley Unit 1 through 2014. Davis-Besse has adequate storage through 2017. FENOC is taking actions to extend the spent fuel storage capacity for Beaver Valley Units 1 and 2 and Perry. Plant modifications to increase the storage capacity of the existing spent fuel storage pool at Beaver Valley Unit 2 are currently under NRC review with approval expected by mid-year 2011. Dry fuel storage is also being pursued at Beaver Valley with completion projected by the end of 2014. Perry dry fuel storage facilities have been completed with the initial dry fuel storage loading pending resolution of a technical issue with the NRC. The Perry initial dry fuel storage loading campaign is targeted for 2012. Both Beaver Valley 2 and Perry maintain sufficient fuel storage capability to continue operations through the targeted completion dates of their respective storage expansion projects. After current on-site storage capacity at the plants is exhausted, additional storage capacity will have to be obtained either through plant modifications, interim off-site disposal, or permanent waste disposal facilities.
The Federal Nuclear Waste Policy Act of 1982 provided for the construction of facilities for the permanent disposal of high-level nuclear wastes, including spent fuel from nuclear power plants operated by electric utilities. NGC has contracts with the DOE for the disposal of spent fuel for Beaver Valley, Davis-Besse and Perry. Yucca Mountain was approved in 2002 as a repository for underground disposal of spent nuclear fuel from nuclear power plants and high level waste from U.S. defense programs. The DOE submitted the license application for Yucca Mountain to the NRC on June 3, 2008. On March 3, 2010, the Department of Energy filed a motion to withdraw its Yucca Mountain license application with prejudice. The Atomic Safety and Licensing Board denied the Department’s withdrawal motion on June 29, 2010. That decision is on appeal to the Commission. However, the current Administration has stated the Yucca Mountain repository will not be completed and a Federal review of potential alternative strategies is being performed.
In parallel, several parties filed actions in the U.S. Circuit Court of Appeals for the D.C. Circuit challenging the Department’s authority to withdraw the license application in light of its obligations under the Nuclear Waste Policy Act. The first case filed wasIn re: Aiken County, filed on February 19, 2010. Robert L. Ferguson, et al. filed a petition on February 25, 2010; State of South Carolina filed on March 26, 2010; and State of Washington filed on April 13, 2010. These cases have since been consolidated. Arguments in the case are scheduled for March 22, 2011. In light of this uncertainty, FirstEnergy intends to make additional arrangements for storage capacity as a contingency for the continuing delays of the DOE acceptance of spent fuel for disposal.
Fuel oil and natural gas are used primarily to fuel peaking units and/or to ignite the burners prior to burning coal when a coal-fired plant is restarted. Fuel oil requirements have historically been low and are forecasted to remain so. Requirements are expected to average approximately 5 million gallons per year over the next five years. Natural gas is currently consumed primarily by peaking units and demand is forecasted at less than 1 million mcf in 2011. FirstEnergy purchased a partially completed combined cycle combustion turbine plant in Fremont Ohio. Construction is scheduled to be completed in 2011.
System Demand
The 2010 net maximum hourly demand for each of the Utilities was:
| • | OE—5,610 MW on July 23, 2010; | ||
| • | Penn—1,028 MW on July 23, 2010; | ||
| • | CEI—4,418 MW on July 23, 2010; | ||
| • | TE—2,122 MW on July 23, 2010; | ||
| • | JCP&L—6,420 MW on July 6, 2010; | ||
| • | Met-Ed—2,932 MW on July 6, 2010; and | ||
| • | Penelec—2,884 MW on July 6, 2010. |
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Supply Plan
Regulated Commodity Sourcing
The Utilities have a default service obligation to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio Companies and Penn’s default service supplies are provided through a competitive procurement process approved by the PUCO and PPUC, respectively. The default service supply for Met-Ed and Penelec was secured through a FERC-approved agreement with FES through 2010, transitioning to a PPUC-approved competitive procurement process in 2011. If any supplier fails to deliver power to any one of the Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a POLR.
Unregulated Commodity Sourcing
FES provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls 13,236 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES has retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2010, FES’ generation was used to serve two primary obligations — affiliated companies utilized approximately 43% of FES’ total generation and retail customers utilized approximately 43% of FES’ total generation. Geographically, approximately 60% of FES’ obligation is located in the MISO market area and 40% is located in the PJM market area.
Regional Reliability
FirstEnergy’s operating companies are located within MISO and PJM and operate under the reliability oversight of a regional entity known as ReliabilityFirst. This regional entity operates under the oversight of the NERC in accordance with a Delegation Agreement approved by the FERC. ReliabilityFirstbegan operations under the NERC on January 1, 2006. On July 20, 2006, the NERC was certified by the FERC as the ERO in the United States pursuant to Section 215 of the FPA and ReliabilityFirstwas certified as a regional entity.
Competition
As a result of actions taken by state legislative bodies, major changes in the electric utility business have occurred in portions of the United States, including Ohio, New Jersey and Pennsylvania, where FirstEnergy’s utility subsidiaries operate. These changes have altered the way traditional integrated utilities conduct their business. FirstEnergy has aligned its business units to participate in the competitive electricity marketplace (see Management’s Discussion and Analysis). FirstEnergy’s Competitive Energy Services segment participates in deregulated energy markets in Ohio, Pennsylvania, Maryland, Michigan, New Jersey, and Illinois through FES.
In New Jersey, JCP&L has procured electric generation supply to serve its BGS customers since 2002 through a statewide auction process approved by the NJBPU. The auction is designed to procure supply for BGS customers at a cost reflective of market conditions. In Ohio, SB221 provides two options for pricing generation in 2009 and beyond — through a negotiated rate plan or a competitive bidding process (see Ohio Regulatory Matters above). In Pennsylvania, all electric distribution companies are required to secure generation for customers in competitive markets effective January 1, 2011.
Seasonality
The sale of electric power is generally a seasonal business and weather patterns can have a material impact on FirstEnergy’s operating results. Demand for electricity in our service territories historically peaks during the summer and winter months, with market prices also generally peaking at that time. Accordingly, FirstEnergy’s annual results of operations and liquidity position may depend disproportionately on its operating performance during the summer and winter. Mild weather conditions may result in lower power sales and consequently lower earnings.
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Research and Development
The Utilities, FES, and FENOC participate in the funding of EPRI, which was formed for the purpose of expanding electric research and development (R&D) under the voluntary sponsorship of the nation’s electric utility industry — public, private and cooperative. Its goal is to mutually benefit utilities and their customers by promoting the development of new and improved technologies to help the utility industry meet present and future electric energy needs in environmentally and economically acceptable ways. EPRI conducts research on all aspects of electric power production and use, including fuels, generation, delivery, energy management and conservation, environmental effects and energy analysis. The majority of EPRI’s research and development projects are directed toward practical solutions and their applications to problems currently facing the electric utility industry.
FirstEnergy participates in other initiatives with industry R&D consortiums and universities to address technology needs for its various business units. Participation in these consortiums helps the company address research needs in areas such as plant operations and maintenance, major component reliability, environmental controls, advanced energy technologies, and transmission and distribution system infrastructure to improve performance, and develop new technologies for advanced energy and grid applications.
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Executive Officers
| Name | Age | Positions Held During Past Five Years | Dates | |||
| A. J. Alexander (A)(B) | 59 | President and Chief Executive Officer Chief Executive Officer (F) | *-present *-present | |||
| W. D. Byrd (B) | 56 | Vice President, Corporate Risk & Chief Risk Officer | 2007-present | |||
| Director — Rates Strategy | *-2007 | |||||
| L. M. Cavalier (B) | 59 | Senior Vice President — Human Resources | 2005-present | |||
| Vice President | *-2005 | |||||
| M. T. Clark (A)(B)(C)(D)(E)(F) | 60 | Executive Vice President and Chief Financial Officer | 2009-present | |||
| Executive Vice President — Strategic Planning & Operations | 2008-2009 | |||||
| Senior Vice President — Strategic Planning & Operations | *-2008 | |||||
| C. E. Jones (A)(B) | 55 | Senior Vice President & President — FirstEnergy Utilities | 2010-present | |||
| President (C) (D) | 2010-present | |||||
| Senior Vice President — Energy Delivery & Customer Service | 2009-2010 | |||||
| President — FirstEnergy Solutions | 2007-2009 | |||||
| Senior Vice President — Energy Delivery & Customer Service | *-2007 | |||||
| J. H. Lash (F) | 60 | President and Chief Nuclear Officer | 2010-present | |||
| Senior Vice President and Chief Operating Officer | 2007-2010 | |||||
| Vice President, Beaver Valley | *-2007 | |||||
| C. D. Lasky (E) | 48 | Vice President — Fossil Operations | 2008-present | |||
| Vice President — Fossil Operations & Air Quality Compliance | 2007-2008 | |||||
| Vice President | *-2007 | |||||
| G. R. Leidich (A)(B) | 60 | Executive Vice President & President — FirstEnergy Generation | 2008-present | |||
| Senior Vice President — Operations (B) | 2007-2008 | |||||
| President and Chief Nuclear Officer (F) | *-2007 | |||||
| D. C. Luff (B) | 63 | Senior Vice President — Governmental Affairs | 2007-present | |||
| Vice President | *-2007 | |||||
| J. F. Pearson | 56 | Vice President and Treasurer | 2006-present | |||
| (A)(B)(C)(D)(E)(F) | Treasurer | *-2006 | ||||
| D. R. Schneider (E) | 49 | President | 2009-present | |||
| Senior Vice President — Energy Delivery & Customer Service (B) | 2007-2009 | |||||
| Vice President (B) | 2006-2007 | |||||
| Vice President (E) | *-2006 | |||||
| L. L. Vespoli (A)(B)(C)(D)(E)(F) | 51 | Executive Vice President and General Counsel | 2008-present | |||
| Senior Vice President and General Counsel | *-2008 | |||||
| H. L. Wagner (A)(B) | 58 | Vice President, Controller and Chief Accounting Officer | *-present | |||
| Vice President and Controller (C)(D)(E)(F) | *-present |
| (A) | Denotes executive officer of FirstEnergy Corp. | |
| (B) | Denotes executive officer of FESC | |
| (C) | Denotes executive officer of OE, CEI and TE. | |
| (D) | Denotes executive officer of Met-Ed, Penelec and Penn. | |
| (E) | Denotes executive officer of FES | |
| (F) | Denotes executive officer of FENOC | |
| * | Indicates position held at least since January 1, 2006. |
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Employees
As of December 31, 2010, FirstEnergy’s subsidiaries had a total of 13,330 employees located in the United States as follows:
| Bargaining | ||||||||
| Total | Unit | |||||||
| Employees | Employees | |||||||
| FESC | 2,796 | 295 | ||||||
| OE | 1,227 | 750 | ||||||
| CEI | 916 | 615 | ||||||
| TE | 394 | 287 | ||||||
| Penn | 207 | 154 | ||||||
| JCP&L | 1,434 | 1,097 | ||||||
| Met-Ed | 706 | 509 | ||||||
| Penelec | 899 | 642 | ||||||
| ATSI | 39 | — | ||||||
| FES | 274 | — | ||||||
| FGCO | 1,751 | 1,140 | ||||||
| FENOC | 2,687 | 982 | ||||||
| Total | 13,330 | 6,471 | ||||||
FirstEnergy Web Site
Each of the registrant’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are also made available free of charge on or through FirstEnergy’s internet Web site at www.firstenergycorp.com. These reports are posted on the Web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, we routinely post important information on our Web site and recognize our Web site is a channel of distribution to reach public investors and as a means of disclosing material non-public information for complying with disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy’s Web site shall not be deemed incorporated into, or to be part of, this report.
| ITEM 1A. | RISK FACTORS |
We operate in a business environment that involves significant risks, many of which are beyond our control. Management of each Registrant regularly evaluates the most significant risks of the Registrant’s businesses and reviews those risks with the FirstEnergy Board of Directors or appropriate Committees of the Board. The following risk factors and all other information contained in this report should be considered carefully when evaluating FirstEnergy and our subsidiaries. These risk factors could affect our financial results and cause such results to differ materially from those expressed in any forward-looking statements made by or on behalf of us. Below, we have identified risks we currently consider material. Additional information on risk factors is included in “Item 1. Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in other sections of this Form 10-K that include forward-looking and other statements involving risks and uncertainties that could impact our business and financial results.
Risks Related to Business Operations
Risks Arising from the Reliability of Our Power Plants and Transmission and Distribution Equipment
Operation of generation, transmission and distribution facilities involves risk, including, the risk of potential breakdown or failure of equipment or processes, due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution delivery systems. Because our transmission facilities are interconnected with those of third parties, the operation of our facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.
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Operation of our power plants below expected capacity could result in lost revenues and increased expenses, including higher operating and maintenance costs, purchased power costs and capital requirements. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of our business. Unplanned outages typically increase our operation and maintenance expenses and may reduce our revenues as a result of selling fewer MWH or may require us to incur significant costs as a result of operating our higher cost units or obtaining replacement power from third parties in the open market to satisfy our forward power sales obligations. Moreover, if we were unable to perform under contractual obligations, penalties or liability for damages could result. FES, FGCO and the Ohio Companies are exposed to losses under their applicable sale-leaseback arrangements for generating facilities upon the occurrence of certain contingent events that could render those facilities worthless. Although we believe these types of events are unlikely to occur, FES, FGCO and the Ohio Companies have a maximum exposure to loss under those provisions of approximately $1.36 billion for FES, $666 million for OE and an aggregate of $622 million for TE and CEI as co-lessees.
We remain obligated to provide safe and reliable service to customers within our franchised service territories. Meeting this commitment requires the expenditure of significant capital resources. Failure to provide safe and reliable service and failure to meet regulatory reliability standards due to a number of factors, including, but not limited to, equipment failure and weather, could adversely affect our operating results through reduced revenues and increased capital and operating costs and the imposition of penalties/fines or other adverse regulatory outcomes.
Changes in Commodity Prices Could Adversely Affect Our Profit Margins
We purchase and sell electricity in the competitive wholesale and retail markets. Increases in the costs of fuel for our generation facilities (particularly coal, uranium and natural gas) can affect our profit margins. Changes in the market price of electricity, which are affected by changes in other commodity costs and other factors, may impact our results of operations and financial position by increasing the amount we pay to purchase power to supply POLR and default service obligations in the states we do business. In addition, the global economy could lead to lower international demand for coal, oil and natural gas, which may lower fossil fuel prices and put downward pressure on electricity prices.
Electricity and fuel prices may fluctuate substantially over relatively short periods of time for a variety of reasons, including:
| • | changing weather conditions or seasonality; | ||
| • | changes in electricity usage by our customers; | ||
| • | illiquidity and credit worthiness of participants in wholesale power and other markets; | ||
| • | transmission congestion or transportation constraints, inoperability or inefficiencies; | ||
| • | availability of competitively priced alternative energy sources; | ||
| • | changes in supply and demand for energy commodities; | ||
| • | changes in power production capacity; | ||
| • | outages at our power production facilities or those of our competitors; | ||
| • | changes in production and storage levels of natural gas, lignite, coal, crude oil and refined products; | ||
| • | changes in legislation and regulation; and | ||
| • | natural disasters, wars, acts of sabotage, terrorist acts, embargoes and other catastrophic events. |
We Are Exposed to Operational, Price and Credit Risks Associated With Selling and Marketing Products in the Power Markets That We Do Not Always Completely Hedge Against
We purchase and sell power at the wholesale level under market-based tariffs authorized by the FERC, and also enter into agreements to sell available energy and capacity from our generation assets. If we are unable to deliver firm capacity and energy under these agreements, we may be required to pay damages. These damages would generally be based on the difference between the market price to acquire replacement capacity or energy and the contract price of the undelivered capacity or energy. Depending on price volatility in the wholesale energy markets, such damages could be significant.Extreme weather conditions, unplanned power plant outages, transmission disruptions, and other factors could affect our ability to meet our obligations, or cause increases in the market price of replacement capacity and energy.
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We attempt to mitigate risks associated with satisfying our contractual power sales arrangements by reserving generation capacity to deliver electricity to satisfy our net firm sales contracts and, when necessary, by purchasing firm transmission service. We also routinely enter into contracts, such as fuel and power purchase and sale commitments, to hedge our exposure to fuel requirements and other energy-related commodities. We may not, however, hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, our results of operations and financial position could be negatively affected.
The Use of Derivative Contracts by Us to Mitigate Risks Could Result in Financial Losses That May Negatively Impact Our Financial Results
We use a variety of non-derivative and derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. In the absence of actively quoted market prices and pricing information from external sources, the valuation of some of these derivative instruments involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of some of these contracts. Also, we could recognize financial losses as a result of volatility in the market values of these contracts or if a counterparty fails to perform.
Financial Derivatives Reforms Could Increase Our Liquidity Needs and Collateral Costs
In July 2010, federal legislation was enacted to reform financial markets that significantly alter how over-the-counter (OTC) derivatives are regulated. The law increased regulatory oversight of OTC energy derivatives, including (1) requiring standardized OTC derivatives to be traded on registered exchanges regulated by the Commodity Futures Trading Commission (CFTC), (2) imposing new and potentially higher capital and margin requirements and (3) authorizing the establishment of overall volume and position limits. The law gives the CFTC authority to exempt end users of energy commodities which could reduce, but not eliminate, the applicability of these measures to us and other end users. These requirements could cause our OTC transactions to be more costly and have an adverse effect on our liquidity due to additional capital requirements. In addition, as these reforms aim to standardize OTC products it could limit the effectiveness of our hedging programs because we would have less ability to tailor OTC derivatives to match the precise risk we are seeking to protect.
Our Risk Management Policies Relating to Energy and Fuel Prices, and Counterparty Credit, Are by Their Very Nature Risk Related, and We Could Suffer Economic Losses Despite Such Policies
We attempt to mitigate the market risk inherent in our energy, fuel and debt positions. Procedures have been implemented to enhance and monitor compliance with our risk management policies, including validation of transaction and market prices, verification of risk and transaction limits, sensitivity analysis and daily portfolio reporting of various risk measurement metrics. Nonetheless, we cannot economically hedge all of our exposures in these areas and our risk management program may not operate as planned. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions reflected in our analyses. Also, our power plants might not produce the expected amount of power during a given day or time period due to weather conditions, technical problems or other unanticipated events, which could require us to make energy purchases at higher prices than the prices under our energy supply contracts. In addition, the amount of fuel required for our power plants during a given day or time period could be more than expected, which could require us to buy additional fuel at prices less favorable than the prices under our fuel contracts. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge.
Our risk management activities, including our power sales agreements with counterparties, rely on projections that depend heavily on judgments and assumptions by management of factors such as future market prices and demand for power and other energy-related commodities. These factors become more difficult to predict and the calculations become less reliable the further into the future these estimates are made. Even when our policies and procedures are followed and decisions are made based on these estimates, results of operations may be diminished if the judgments and assumptions underlying those calculations prove to be inaccurate.
We also face credit risks from parties with whom we contract who could default in their performance, in which cases we could be forced to sell our power into a lower-priced market or make purchases in a higher-priced market than existed at the time of executing the contract. Although we have established risk management policies and programs, including credit policies to evaluate counterparty credit risk, there can be no assurance that we will be able to fully meet our obligations, that we will not be required to pay damages for failure to perform or that we will not experience counterparty non-performance or that we will collect for voided contracts. If counterparties to these arrangements fail to perform, we may be forced to enter into alternative hedging arrangements or honor underlying commitments at then-current market prices. In that event, our financial results could be adversely affected.
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Nuclear Generation Involves Risks that Include Uncertainties Relating to Health and Safety, Additional Capital Costs, the Adequacy of Insurance Coverage and Nuclear Plant Decommissioning
We are subject to the risks of nuclear generation, including but not limited to the following:
| • | the potential harmful effects on the environment and human health resulting from unplanned radiological releases associated with the operation of our nuclear facilities and the storage, handling and disposal of radioactive materials; | ||
| • | limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with our nuclear operations or those of others in the United States; | ||
| • | uncertainties with respect to contingencies and assessments if insurance coverage is inadequate; and | ||
| • | uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed operation including increases in minimum funding requirements or costs of completion. |
The NRC has broad authority under federal law to impose licensing security and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines and/or shut down a unit, depending upon its assessment of the severity of the situation, until compliance is achieved. Revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants, including ours. Also, a serious nuclear incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or relicensing of any domestic nuclear unit.
Our nuclear facilities are insured under NEIL policies issued for each plant. Under these policies, up to $2.8 billion of insurance coverage is provided for property damage and decontamination and decommissioning costs. We have also obtained approximately $2.0 billion of insurance coverage for replacement power costs. Under these policies, we can be assessed a maximum of approximately $79 million for incidents at any covered nuclear facility occurring during a policy year that are in excess of accumulated funds available to the insurer for paying losses.
The Price-Anderson Act limits the public liability that can be assessed with respect to a nuclear power plant to $12.6 billion (assuming 104 units licensed to operate in the United States) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $12.2 billion provided by an industry retrospective rating plan. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per year) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Our maximum potential exposure under these provisions would be $470 million per incident but not more than $70 million in any one year.
Capital Market Performance and Other Changes May Decrease the Value of Decommissioning Trust Fund, Pension Fund Assets and Other Trust Funds Which Then Could Require Significant Additional Funding
Our financial statements reflect the values of the assets held in trust to satisfy our obligations to decommission our nuclear generation facilities and under pension and other post-retirement benefit plans. The value of certain of the assets held in these trusts do not have readily determinable market values. Changes in the estimates and assumptions inherent in the value of these assets could affect the value of the trusts. If the value of the assets held by the trusts declines by a material amount, our funding obligation to the trusts could materially increase. These assets are subject to market fluctuations and will yield uncertain returns, which may fall below our projected return rates. Forecasting investment earnings and costs to decommission nuclear generating stations, to pay future pensions and other obligations requires significant judgment, and actual results may differ significantly from current estimates. Capital market conditions that generate investment losses or greater liability levels can negatively impact our results of operations and financial position.
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We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets and the States in Which We Do Business
As a result of the EPACT, owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by the NERC and approved by FERC as well as mandatory reliability standards and energy efficiency requirements imposed by each of the states in which we operate. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties.
Reliability standards that were historically subject to voluntary compliance are now mandatory and could subject us to potential civil penalties for violations which could negatively impact our business. The FERC can now impose penalties of $1.0 million per day for failure to comply with these mandatory electric reliability standards.
In addition to direct regulation by the FERC and the states, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs. Although these entities are themselves ultimately regulated by the FERC, they can impose rules, restrictions and terms of service that are quasi-regulatory in nature and can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the potential exercise of market power and to ensure the market functions. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, the RTOs may direct our transmission owning affiliates to build new transmission facilities to meet the reliability requirements of the RTO or to provide new or expanded transmission service under the RTO tariffs.
We Rely on Transmission and Distribution Assets That We Do Not Own or Control to Deliver Our Wholesale Electricity. If Transmission is Disrupted Including Our Own Transmission, or Not Operated Efficiently, or if Capacity is Inadequate, Our Ability to Sell and Deliver Power May Be Hindered
We depend on transmission and distribution facilities owned and operated by utilities and other energy companies to deliver the electricity we sell. If transmission is disrupted (as a result of weather, natural disasters or other reasons) or not operated efficiently by independent system operators, in applicable markets, or if capacity is inadequate, our ability to sell and deliver products and satisfy our contractual obligations may be hindered, or we may be unable to sell products on the most favorable terms. In addition, in certain of the markets in which we operate, we may be required to pay for congestion costs if we schedule delivery of power between congestion zones during periods of high demand. If we are unable to hedge or recover for such congestion costs in retail rates, our financial results could be adversely affected.
Demand for electricity within our Utilities’ service areas could stress available transmission capacity requiring alternative routing or curtailing electricity usage that may increase operating costs or reduce revenues with adverse impacts to results of operations. In addition, as with all utilities, potential concerns over transmission capacity could result in MISO, PJM or the FERC requiring us to upgrade or expand our transmission system, requiring additional capital expenditures.
The FERC requires wholesale electric transmission services to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, it is possible that fair and equal access to transmission systems will not be available or that sufficient transmission capacity will not be available to transmit electricity as we desire. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether independent system operators in applicable markets will operate the transmission networks, and provide related services, efficiently.
Disruptions in Our Fuel Supplies Could Occur, Which Could Adversely Affect Our Ability to Operate Our Generation Facilities and Impact Financial Results
We purchase fuel from a number of suppliers. The lack of availability of fuel at expected prices, or a disruption in the delivery of fuel which exceeds the duration of our on-site fuel inventories, including disruptions as a result of weather, increased transportation costs or other difficulties, labor relations or environmental or other regulations affecting our fuel suppliers, could cause an adverse impact on our ability to operate our facilities, possibly resulting in lower sales and/or higher costs and thereby adversely affect our results of operations. Operation of our coal-fired generation facilities is highly dependent on our ability to procure coal. Although we have long-term contracts in place for our coal and coal transportation needs, power generators in the Midwest and the Northeast have experienced significant pressures on available coal supplies that are either transportation or supply related. If prices for physical delivery are unfavorable, our financial condition, results of operations and cash flows could be materially adversely affected.
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Temperature Variations as well as Weather Conditions or other Natural Disasters Could Have a Negative Impact on Our Results of Operations and Demand Significantly Below or Above Our Forecasts Could Adversely Affect Our Energy Margins
Weather conditions directly influence the demand for electric power. Demand for power generally peaks during the summer and winter months, with market prices also typically peaking at that time. Overall operating results may fluctuate based on weather conditions. In addition, we have historically sold less power, and consequently received less revenue, when weather conditions are milder. Severe weather, such as tornadoes, hurricanes, ice or snow storms, or droughts or other natural disasters, may cause outages and property damage that may require us to incur additional costs that are generally not insured and that may not be recoverable from customers. The effect of the failure of our facilities to operate as planned under these conditions would be particularly burdensome during a peak demand period.
Customer demand could change as a result of severe weather conditions or other circumstances over which we have no control. We satisfy our electricity supply obligations through a portfolio approach of providing electricity from our generation assets, contractual relationships and market purchases. A significant increase in demand could adversely affect our energy margins if we are required under the terms of the default service tariffs to provide the energy supply to fulfill this increased demand at capped rates, which we expect would remain below the wholesale prices at which we would have to purchase the additional supply if needed or, if we had available capacity, the prices at which we could otherwise sell the additional supply. Accordingly, any significant change in demand could have a material adverse effect on our results of operations and financial position.
We Are Subject to Financial Performance Risks Related to Regional and General Economic Cycles and also Related to Heavy Manufacturing Industries such as Automotive and Steel
Our business follows the economic cycles of our customers. As our retail strategy is centered around the sale of output from our generating plants generally where that power will reach, therefore, we are more directly impacted by the economic conditions in our primary markets (i.e., Pennsylvania, Ohio, Maryland, New Jersey, Michigan and Illinois). Declines in demand for electricity as a result of a regional economic downturn would be expected to reduce overall electricity sales and reduce our revenues. Electric generation sales volume has been, and is expected to continue to be, influenced by circumstances in automotive, steel and other heavy industries.
Increases in Customer Electric Rates and Economic Uncertainty May Lead to a Greater Amount of Uncollectible Customer Accounts
Our operations are impacted by the economic conditions in our service territories and those conditions could negatively impact the rate of delinquent customer accounts and our collections of accounts receivable which could adversely impact our financial condition, results of operations and cash flows.
The Goodwill of One or More of Our Operating Subsidiaries May Become Impaired, Which Would Result in Write-Offs of the Impaired Amounts
Goodwill could become impaired at one or more of our operating subsidiaries. The actual timing and amounts of any goodwill impairments in future years would depend on many uncertainties, including changing interest rates, utility sector market performance, our capital structure, market prices for power, results of future rate proceedings, operating and capital expenditure requirements, the value of comparable utility acquisitions, environmental regulations and other factors.
We Face Certain Human Resource Risks Associated with the Availability of Trained and Qualified Labor to Meet Our Future Staffing Requirements
We must find ways to retain our aging skilled workforce while recruiting new talent to mitigate losses in critical knowledge and skills due to retirements. Mitigating these risks could require additional financial commitments.
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Significant Increases in Our Operation and Maintenance Expenses, Including Our Health Care and Pension Costs, Could Adversely Affect Our Future Earnings and Liquidity
We continually focus on limiting, and reducing where possible, our operation and maintenance expenses. However, we expect cost pressures could increase as we continue to implement our retail sales strategy. We expect to continue to face increased cost pressures in the areas of health care and pension costs. We have experienced significant health care cost inflation in the last few years, and we expect our cash outlay for health care costs, including prescription drug coverage, to continue to increase despite measures that we have taken and expect to take requiring employees and retirees to bear a higher portion of the costs of their health care benefits. The measurement of our expected future health care and pension obligations and costs is highly dependent on a variety of assumptions, many of which relate to factors beyond our control. These assumptions include investment returns, interest rates, health care cost trends, benefit design changes, salary increases, the demographics of plan participants and regulatory requirements. If actual results differ materially from our assumptions, our costs could be significantly increased.
Our Business is Subject to the Risk that Sensitive Customer Data May be Compromised, Which Could Result in an Adverse Impact to Our Reputation and/or Results of Operations
Our business requires access to sensitive customer data, including personal and credit information, in the ordinary course of business. A security breach may occur, despite security measures taken by us and required of vendors. If a significant or widely publicized breach occurred, our business reputation may be adversely affected, customer confidence may be diminished, or we may become subject to legal claims, fines or penalties, any of which could have a negative impact on our business and/or results of operations.
Acts of War or Terrorism Could Negatively Impact Our Business
The possibility that our infrastructure, such as electric generation, transmission and distribution facilities, or that of an interconnected company, could be direct targets of, or indirect casualties of, an act of war or terrorism, could result in disruption of our ability to generate, purchase, transmit or distribute electricity. Any such disruption could result in a decrease in revenues and additional costs to purchase electricity and to replace or repair our assets, which could have a material adverse impact on our results of operations and financial condition.
Capital Improvements and Construction Projects May Not be Completed Within Forecasted Budget, Schedule or Scope Parameters
Our business plan calls for extensive capital investments. We may be exposed to the risk of substantial price increases in the costs of labor and materials used in construction. We have engaged numerous contractors and entered into a large number of agreements to acquire the necessary materials and/or obtain the required construction-related services. As a result, we are also exposed to the risk that these contractors and other counterparties could breach their obligations to us. Such risk could include our contractors’ inabilities to procure sufficient skilled labor as well as potential work stoppages by that labor force. Should the counterparties to these arrangements fail to perform, we may be forced to enter into alternative arrangements at then-current market prices that may exceed our contractual prices, with resulting delays in those and other projects. Although our agreements are designed to mitigate the consequences of a potential default by the counterparty, our actual exposure may be greater than these mitigation provisions. This could have negative financial impacts such as incurring losses or delays in completing construction projects.
Changes in Technology May Significantly Affect Our Generation Business by Making Our Generating Facilities Less Competitive
We primarily generate electricity at large central facilities. This method results in economies of scale and lower costs than newer technologies such as fuel cells, microturbines, windmills and photovoltaic solar cells. It is possible that advances in technologies will reduce their costs to levels that are equal to or below that of most central station electricity production, which could have a material adverse effect on our results of operations.
We May Acquire Assets That Could Present Unanticipated Issues for Our Business in the Future, Which Could Adversely Affect Our Ability to Realize Anticipated Benefits of Those Acquisitions
Asset acquisitions involve a number of risks and challenges, including: management attention; integration with existing assets; difficulty in evaluating the requirements associated with the assets prior to acquisition, operating costs, potential environmental and other liabilities, and other factors beyond our control; and an increase in our expenses and working capital requirements. Any of these factors could adversely affect our ability to achieve anticipated levels of cash flows or realize other anticipated benefits from any such asset acquisition.
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Ability of Certain FirstEnergy Companies to Meet Their Obligations to Other FirstEnergy Companies
Certain of the FirstEnergy companies have obligations to other FirstEnergy companies because of transactions involving energy, coal, other commodities, services, and because of hedging transactions. If one FirstEnergy entity failed to perform under any of these arrangements, other FirstEnergy entities could incur losses. Their results of operations, financial position, or liquidity could be adversely affected, resulting in the nondefaulting FirstEnergy entity being unable to meet its obligations to unrelated third parties. Our hedging activities are generally undertaken with a view to overall FirstEnergy exposures. Some FirstEnergy companies may therefore be more or less hedged than if they were to engage in such transactions alone.
Risks Associated With Our Proposed Merger With Allegheny
We May be Unable to Obtain the Approvals Required to Complete Our Merger with Allegheny or, in Order to do so, the Combined Company May be Required to Comply With Material Restrictions or Conditions
On February 11, 2010, we announced the execution of a merger agreement with Allegheny. The only regulatory approval pending is from the PPUC. The PPUC could impose conditions on the completion, or require changes to the terms, of the merger, including restrictions or conditions on the business, operations, or financial performance of the combined company following completion of the merger. These conditions or changes could have the effect of delaying completion of the merger or imposing additional costs on or limiting the revenues of the combined company following the merger, which could have a material adverse effect on the financial results of the combined company and/or cause either us or Allegheny to abandon the merger.
If Completed, Our Merger with Allegheny May Not Achieve Its Intended Results
We and Allegheny entered into the merger agreement with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to both the regulated utility operations and the generation business. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including whether the business of Allegheny is integrated in an efficient and effective manner. Failure to achieve these anticipated benefits could result in increased costs, decreases in the amount of expected revenues generated by the combined company and diversion of management’s time and energy and could have an adverse effect on the combined company’s business, financial results and prospects.
We Will be Subject to Business Uncertainties and Contractual Restrictions While the Merger with Allegheny is Pending That Could Adversely Affect Our Financial Results
Uncertainty about the effect of the merger with Allegheny on employees and customers may have an adverse effect on us. Although we intend to take steps designed to reduce any adverse effects, these uncertainties may impair our ability to attract, retain and motivate key personnel until the merger is completed and for a period of time thereafter, and could cause customers, suppliers and others that deal with us to seek to change existing business relationships.
Employee retention and recruitment may be particularly challenging prior to the completion of the merger, as employees and prospective employees may experience uncertainty about their future roles with the combined company. If, despite our retention and recruiting efforts, key employees depart or fail to accept employment with us because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with the combined company, our financial results could be affected.
The pursuit of the merger and the preparation for the integration of Allegheny into our company may place a significant burden on management and internal resources. The diversion of management attention away from day-to-day business concerns and any difficulties encountered in the transition and integration process could affect our financial results.
In addition, the merger agreement restricts us, without Allegheny‘s consent, from making certain acquisitions and taking other specified actions until the merger occurs or the merger agreement terminates. These restrictions may prevent us from pursuing otherwise attractive business opportunities and making other changes to our business prior to completion of the merger or termination of the merger agreement.
Failure to Complete Our Merger with Allegheny Could Negatively Impact Our Stock Price and Our Future Business and Financial Results
If our merger with Allegheny is not completed, our ongoing business and financial results may be adversely affected and we would be subject to a number of risks, including the following:
| • | We may be required, under specified circumstances set forth in the Merger Agreement, to pay Allegheny a termination fee of $350 million and/or Allegheny’s reasonable out-of-pocket transaction expenses up to $45 million; | ||
| • | we would be required to pay costs relating to the merger, including legal, accounting, financial advisory, filing and printing costs, whether or not the merger is completed; and | ||
| • | matters relating to our merger with Allegheny (including integration planning) may require substantial commitments of time and resources by our management, which could otherwise have been devoted to other opportunities that may have been beneficial to us. |
We could also be subject to litigation related to any failure to complete our merger with Allegheny. If our merger is not completed, these risks may materialize and may adversely affect our business, financial results and stock price.
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Risks Associated With Regulation
Complex and Changing Government Regulations Could Have a Negative Impact on Our Results of Operations
We are subject to comprehensive regulation by various federal, state and local regulatory agencies that significantly influence our operating environment. Changes in, or reinterpretations of, existing laws or regulations, or the imposition of new laws or regulations, could require us to incur additional costs or change the way we conduct our business, and therefore could have an adverse impact on our results of operations.
Our utility subsidiaries currently provide service at rates approved by one or more regulatory commissions. Thus, the rates a utility is allowed to charge may or may not be set to recover its expenses at any given time. Additionally, there may also be a delay between the timing of when costs are incurred and when costs are recovered. For example, we may be unable to timely recover the costs for our energy efficiency investments, expenses and additional capital or lost revenues resulting from the implementation of aggressive energy efficiency programs. While rate regulation is premised on providing an opportunity to earn a reasonable return on invested capital and recovery of operating expenses, there can be no assurance that the applicable regulatory commission will determine that all of our costs have been prudently incurred or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of our costs in a timely manner. For example, our utility subsidiaries’ ability to timely recover rates and charges associated with integration of the ATSI footprint into PJM is uncertain.
Regulatory Changes in the Electric Industry, Including a Reversal, Discontinuance or Delay of the Present Trend Toward Competitive Markets, Could Affect Our Competitive Position and Result in Unrecoverable Costs Adversely Affecting Our Business and Results of Operations
As a result of restructuring initiatives, changes in the electric utility business have occurred, and are continuing to take place throughout the United States, including the states in which we do business. These changes have resulted, and are expected to continue to result, in fundamental alterations in the way utilities conduct their business.
Some states that have deregulated generation service have experienced difficulty in transitioning to market-based pricing. In some instances, state and federal government agencies and other interested parties have made proposals to impose rate cap extensions or otherwise delay market restructuring or even re-regulate areas of these markets that have previously been deregulated. Although we expect wholesale electricity markets to continue to be competitive, proposals to re-regulate our industry may be made, and legislative or other action affecting the electric power restructuring process may cause the process to be delayed, discontinued or reversed in the states in which we currently, or may in the future, operate. Such delays, discontinuations or reversals of electricity market restructuring in the markets in which we operate could have an adverse impact on our results of operations and financial condition.
The FERC and the U.S. Congress propose changes from time to time in the structure and conduct of the electric utility industry. If the restructuring, deregulation or re-regulation efforts result in decreased margins or unrecoverable costs, our business and results of operations would be adversely affected. We cannot predict the extent or timing of further efforts to restructure, deregulate or re-regulate our business or the industry.
The Prospect of Rising Rates Could Prompt Legislative or Regulatory Action to Restrict or Control Such Rate Increases. This In Turn Could Create Uncertainty Affecting Planning, Costs and Results of Operations and May Adversely Affect the Utilities’ Ability to Recover Their Costs, Maintain Adequate Liquidity and Address Capital Requirements
Increases in utility rates, such as may follow a period of frozen or capped rates, can generate pressure on legislators and regulators to take steps to control those increases. Such efforts can include some form of rate increase moderation, reduction or freeze. The public discourse and debate can increase uncertainty associated with the regulatory process, the level of rates and revenues, and the ability to recover costs. Such uncertainty restricts flexibility and resources, given the need to plan and ensure available financial resources. Such uncertainty also affects the costs of doing business. Such costs could ultimately reduce liquidity, as suppliers tighten payment terms, and increase costs of financing, as lenders demand increased compensation or collateral security to accept such risks.
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Our Profitability is Impacted by Our Affiliated Companies’ Continued Authorization to Sell Power at Market-Based Rates
The FERC granted FES, FGCO and NGC authority to sell electricity at market-based rates. These orders also granted them waivers of certain FERC accounting, record-keeping and reporting requirements. The Utilities also have market-based rate authority. The FERC’s orders that grant this market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that these companies can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. As a condition to the orders granting the generating companies market-based rate authority, every three years they are required to file a market power update to show that they continue to meet the FERC’s standards with respect to generation market power and other criteria used to evaluate whether entities qualify for market-based rates. FES, FGCO, NGC and the Utilities renewed this authority for PJM in 2008 and MISO in 2009. On December 30, 2010, FES, FGCO, NGC and the Utilities filed to renew this authority for operations within PJM. If any of these companies were to lose their market-based rate authority, they would be required to obtain the FERC’s acceptance to sell power at cost-based rates. FES, FGCO and NGC could also lose their waivers, and become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.
There Are Uncertainties Relating to Our Participation in RTOs
RTO rules could affect our ability to sell power produced by our generating facilities to users in certain markets due to transmission constraints and attendant congestion costs. The prices in day-ahead and real-time energy markets and RTO capacity markets have been subject to price volatility. Administrative costs imposed by RTOs, including the cost of administering energy markets, have also increased. The rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. To the degree we incur significant additional fees and increased costs to participate in an RTO, and we are limited with respect to recovery of such costs from retail customers, we may suffer financial harm. While RTO rates for transmission service are cost based, our revenues from customers to whom we currently provide transmission services may not reflect all of the administrative and market-related costs imposed under the RTO tariff. In addition, we may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. Finally, we may be required to expand our transmission system according to decisions made by an RTO rather than our internal planning process. As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.
The MISO has proposed changes to its rates and tariffs that may result or cause significant charges to ATSI or the Ohio Companies or Penn upon their respective withdrawal from the MISO on May 31, 2011. The implementation of these and other new market designs has the potential to increase our costs of transmission, costs associated with inefficient generation dispatching, costs of participation in the market and costs associated with estimated payment settlements.
Because it remains unclear which companies will be participating in the various regional power markets, or how RTOs will ultimately develop and operate, or what region they will cover, we cannot fully assess the impact that these power markets or other ongoing RTO developments may have.
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A Significant Delay in or Challenges to Various Elements of ATSI’s Consolidation into PJM, including but not Limited to, the Intervention of Parties to the Regulatory Proceedings Could have a Negative Impact on Our Results of Operations and Financial Condition
On December 17, 2009, FERC authorized, subject to certain conditions, FirstEnergy to consolidate its transmission assets and operations that currently are located in MISO into PJM; such consolidation to be effective on June 1, 2011. The consolidation will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Consolidation on June 1, 2011 will coincide with delivery of power under the next competitive generation procurement process for the Ohio Companies. On December 17, 2009, and after FERC issued the order, ATSI executed and delivered to PJM those legal documents necessary to implement its consolidation into PJM. On December 18, 2009, the Ohio Companies and Penn executed and delivered to PJM those legal documents necessary to follow ATSI into PJM. Currently, ATSI, the Ohio Companies and Penn are expected to consolidate into PJM as planned on June 1, 2011.
On February 1, 2011, ATSI filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. Numerous parties are expected to intervene and file responsive comments. Our expectation is that ATSI will enter PJM as scheduled on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. Additional FERC proceedings are either pending or expected in which the amount of exit fees, transmission cost allocations, and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the Midwest ISO will be determined. In addition, certain other parties continue to protest aspects of the move into PJM, and certain of these matters remain outstanding and will be resolved in future FERC proceedings.A ruling by FERC or any other regulator with jurisdiction in favor of one or more of the intervening or protesting parties (and against FirstEnergy) on one or more of the disputed issues could result in a negative impact on our results of operations and financial condition.
Energy Conservation and Energy Price Increases Could Negatively Impact Our Financial Results
A number of regulatory and legislative bodies have introduced requirements and/or incentives to reduce energy consumption by certain dates. Conservation programs could impact our financial results in different ways. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our merchant generation and other unregulated business activities could be adversely impacted. We currently have energy efficiency riders in place to recover the cost of these programs either at or near a current recovery timeframe in Ohio and Pennsylvania. In New Jersey, we recover the costs for energy efficiency programs through the SBC. Currently only Ohio has provisions for recovery of lost revenues. In our regulated operations, conservation could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that result in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We could also be impacted if any future energy price increases result in a decrease in customer usage. Our results could be affected if we are unable to increase our customer’s participation in our energy efficiency programs. We are unable to determine what impact, if any, conservation and increases in energy prices will have on our financial condition or results of operations.
Our Business and Activities are Subject to Extensive Environmental Requirements and Could be Adversely Affected by such Requirements
We may be forced to shut down facilities, either temporarily or permanently, if we are unable to comply with certain environmental requirements, or if we make a determination that the expenditures required to comply with such requirements are uneconomical. In fact, we are exposed to the risk that such electric generating plants would not be permitted to continue to operate if pollution control equipment is not installed by prescribed deadlines.
The EPA is Conducting NSR Investigations at a Number of Our Generating Plants, the Results of Which Could Negatively Impact Our Results of Operations and Financial Condition
We may be subject to risks in connection with changing or conflicting interpretations of existing laws and regulations. For example, applicable standards under the EPA’s NSR initiatives remain in flux. Under the CAA, modification of our generation facilities in a manner that causes increased emissions could subject our existing facilities to the far more stringent NSR standards applicable to new facilities.
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The EPA has taken the view that many companies, including many energy producers, have been modifying emissions sources in violation of NSR standards in connection with work believed by the companies to be routine maintenance. We are currently involved in litigation and EPA investigations concerning alleged violations of the NSR standards at certain of our existing and former generating facilities. We intend to vigorously pursue and defend our position in these environmental matters but FGCO is unable to predict their outcomes. If NSR and similar requirements are imposed on our generation facilities, in addition to the possible imposition of fines, compliance could entail significant capital investments in pollution control technology, which could have an adverse impact on our business, results of operations, cash flows and financial condition. For a more complete discussion see “Environmental Matters.”
Costs of Compliance with Environmental Laws are Significant, and the Cost of Compliance with Future Environmental Laws, Including Limitations on GHGEmissions, Could Adversely Affect Cash Flow and Profitability
Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations. Compliance with these legal requirements requires us to incur costs for environmental monitoring, installation of pollution control equipment, emission fees, maintenance, upgrading, remediation and permitting at our facilities. These expenditures have been significant in the past and may increase in the future. If the cost of compliance with existing environmental laws and regulations does increase, it could adversely affect our business and results of operations, financial position and cash flows. Moreover, changes in environmental laws or regulations may materially increase our costs of compliance or accelerate the timing of capital expenditures. Because of the deregulation of generation, we may not directly recover through rates additional costs incurred for such compliance. Our compliance strategy, although reasonably based on available information, may not successfully address future relevant standards and interpretations. If we fail to comply with environmental laws and regulations, even if caused by factors beyond our control or new interpretations of longstanding requirements, that failure could result in the assessment of civil or criminal liability and fines. In addition, any alleged violation of environmental laws and regulations may require us to expend significant resources to defend against any such alleged violations.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. Environmental advocacy groups, other organizations and some agencies in the United States are focusing considerable attention on carbon dioxide emissions from power generation facilities and their potential role in climate change. Many states and environmental groups have also challenged certain of the federal laws and regulations relating to air emissions as not being sufficiently strict. Also, claims have been made alleging that CO2 emissions from power generating facilities constitute a public nuisance under federal and/or state common law. Private individuals may seek to enforce environmental laws and regulations against us and could allege personal injury or property damage from exposure to hazardous materials. Recently the courts have begun to acknowledge these claims and may order us to reduce GHG emissions in the future. There is a growing consensus in the United States and globally that GHG emissions are a major cause of global warming and that some form of regulation will be forthcoming at the federal level with respect to GHG emissions (including carbon dioxide) and such regulation could result in the creation of substantial additional costs in the form of taxes or emission allowances. As a result, it is possible that state and federal regulations will be developed that will impose more stringent limitations on emissions than are currently in effect. In December 2009, the EPA issued an “endangerment and cause or contributing finding” for GHG under the CAA, which will allow the EPA to craft rules that directly regulate GHG. This “finding” triggered several regulatory actions under the CAA, resulting, among other things in the regulation of GHG emissions from large stationary sources. Although several bills have been introduced at the state and federal level that would compel carbon dioxide emission reductions, none have advanced through the legislature. Due to the uncertainty of control technologies available to reduce greenhouse gas emissions including CO2, as well as the unknown nature of potential compliance obligations should climate change regulations be enacted, we cannot provide any assurance regarding the potential impacts these future regulations would have on our operations. In addition, any legal obligation that would require us to substantially reduce our emissions could require extensive mitigation efforts and, in the case of carbon dioxide legislation, would raise uncertainty about the future viability of fossil fuels, particularly coal, as an energy source for new and existing electric generation facilities. Until specific regulations are promulgated, the impact that any new environmental regulations, voluntary compliance guidelines, enforcement initiatives, or legislation may have on our results of operations, financial condition or liquidity is not determinable.
At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
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In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure GHG emissions commencing in 2010 and begin to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
The EPA’s CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. In July 2010, the EPA proposed the CATR to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial.
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOX emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. On January 20, 2011, the U.S. District Court for the District of Columbia denied a motion by the EPA for an extension of the deadline to issue final rules, ordering the EPA to issue such rules by February 21, 2011. The EPA also entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, various states have water quality standards applicable to FirstEnergy’s operations.
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The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’s cooling water system). The EPA has taken the position that until further rulemaking occurs; permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On November 19, 2010, the Ohio EPA issued a permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by April 1, 2013. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures. Also, If either the federal or state final regulations require retrofitting of cooling water intake structures (cooling towers) at any of our power plants, and if installation of such cooling towers is not technically or economically feasible, we may be forced to take actions which could adversely impact our results of operations and financial condition.
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Physical Risks Associated with Climate Change May Impact Our Results of Operations and Cash Flows.
Physical risks of climate change, such as more frequent or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, could affect some, or all, of our operations. 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 Utilities’ 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. Finally, climate change could affect the availability of a secure and economical supply of water in some locations, which is essential for continued operation of generating plants.
Remediation of Environmental Contamination at Current or Formerly Owned Facilities
We are subject to liability under environmental laws for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances that we may have generated regardless of whether the liabilities arose before, during or after the time we owned or operated the facilities. Remediation activities associated with our former MGP operations are one source of such costs. We are currently involved in a number of proceedings relating to sites where other hazardous substances have been deposited and may be subject to additional proceedings in the future. We also have current or previous ownership interests in sites associated with the production of gas and the production and delivery of electricity for which we may be liable for additional costs related to investigation, remediation and monitoring of these sites. Citizen groups or others may bring litigation over environmental issues including claims of various types, such as property damage, personal injury, and citizen challenges to compliance decisions on the enforcement of environmental requirements, such as opacity and other air quality standards, which could subject us to penalties, injunctive relief and the cost of litigation. We cannot predict the amount and timing of all future expenditures (including the potential or magnitude of fines or penalties) related to such environmental matters, although we expect that they could be material.
In some cases, a third party who has acquired assets from us has assumed the liability we may otherwise have for environmental matters related to the transferred property. If the transferee fails to discharge the assumed liability or disputes its responsibility, a regulatory authority or injured person could attempt to hold us responsible, and our remedies against the transferee may be limited by the financial resources of the transferee.
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Availability and Cost of Emission Credits Could Materially Impact Our Costs of Operations
We are required to maintain, either by allocation or purchase, sufficient emission credits to support our operations in the ordinary course of operating our power generation facilities. These credits are used to meet our obligations imposed by various applicable environmental laws. If our operational needs require more than our allocated allowances of emission credits, we may be forced to purchase such credits on the open market, which could be costly. If we are unable to maintain sufficient emission credits to match our operational needs, we may have to curtail our operations so as not to exceed our available emission credits, or install costly new emissions controls. As we use the emissions credits that we have purchased on the open market, costs associated with such purchases will be recognized as operating expense. If such credits are available for purchase, but only at significantly higher prices, the purchase of such credits could materially increase our costs of operations in the affected markets. Laws and regulations such as CAIR may, and are, being revised and as CAIR is being rewritten it is creating uncertainty in many areas, including but not limited to, the annual NOx emission allowances beyond 2010.
Mandatory Renewable Portfolio Requirements Could Negatively Affect Our Costs
If federal or state legislation mandates the use of renewable and alternative fuel sources, such as wind, solar, biomass and geothermal and such legislation would not also provide for adequate cost recovery, it could result in significant changes in our business, including renewable energy credit purchase costs, purchased power and potentially renewable energy credit costs and capital expenditures. We are unable to predict what impact, if any, these changes may have on our financial condition or results of operations.
We Are and May Become Subject to Legal Claims Arising from the Presence of Asbestos or Other Regulated Substances at Some of Our Facilities
We have been named as a defendant in pending asbestos litigation involving multiple plaintiffs and multiple defendants. In addition, asbestos and other regulated substances are, and may continue to be, present at our facilities where suitable alternative materials are not available. We believe that any remaining asbestos at our facilities is contained. The continued presence of asbestos and other regulated substances at these facilities, however, could result in additional actions being brought against us.
The Continuing Availability and Operation of Generating Units is Dependent on Retaining the Necessary Licenses, Permits, and Operating Authority from Governmental Entities, Including the NRC
We are required to have numerous permits, approvals and certificates from the agencies that regulate our business. We believe the necessary permits, approvals and certificates have been obtained for our existing operations and that our business is conducted in accordance with applicable laws; however, we are unable to predict the impact on our operating results from future regulatory activities of any of these agencies and we are not assured that any such permits, approvals or certifications will be renewed.
Future Changes in Financial Accounting Standards May Affect Our Reported Financial Results
The SEC, FASB or other authoritative bodies or governmental entities may issue new pronouncements or new interpretations of existing accounting standards that may require us to change our accounting policies. These changes are beyond our control, can be difficult to predict and could materially impact how we report our financial condition and results of operations. We could be required to apply a new or revised standard retroactively, which could adversely affect our financial position. The SEC has announced a work plan to aid in its evaluation of the impact that the use of IFRS by U.S. public companies would have on the U.S. securities market. Given the results of the work plan, the SEC expects to make a determination in 2011 regarding the mandatory adoption of IFRS. We are currently assessing the impact that this potential change would have on our consolidated financial statements and we will continue to monitor the development of the potential implementation of IFRS.
Increases in Taxes and Fees.
Due to the revenue needs of the United States and the states and jurisdictions in which we operate, various tax and fee increases may be proposed or considered. We cannot predict whether legislation or regulation will be introduced, the form of any legislation or regulation, whether any such legislation or regulation will be passed by the state legislatures or regulatory bodies. If enacted, these changes could increase tax costs and could have a negative impact on our results of operations, financial condition and cash flows.
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Risks Associated With Financing and Capital Structure
Interest Rates and/or a Credit Rating Downgrade Could Negatively Affect Our Financing Costs, Our Ability to Access Capital and Our Requirement to Post Collateral
We have near-term exposure to interest rates from outstanding indebtedness indexed to variable interest rates, and we have exposure to future interest rates to the extent we seek to raise debt in the capital markets to meet maturing debt obligations and fund construction or other investment opportunities. Past disruptions in capital and credit markets have resulted in higher interest rates on new publicly issued debt securities, increased costs for certain of our variable interest rate debt securities and failed remarketings (all of which were eventually remarketed) of variable interest rate tax-exempt debt issued to finance certain of our facilities. Continuation of these disruptions could increase our financing costs and adversely affect our results of operations. Also, interest rates could change as a result of economic or other events that our risk management processes were not established to address. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events lead to greater losses or costs than our risk management positions were intended to hedge. Although we employ risk management techniques to hedge against interest rate volatility, significant and sustained increases in market interest rates could materially increase our financing costs and negatively impact our reported results of operations.
We rely on access to bank and capital markets as sources of liquidity for cash requirements not satisfied by cash from operations. A downgrade in our credit ratings from the nationally recognized credit rating agencies, particularly to a level below investment grade, could negatively affect our ability to access the bank and capital markets, especially in a time of uncertainty in either of those markets, and may require us to post cash collateral to support outstanding commodity positions in the wholesale market, as well as available letters of credit and other guarantees. A rating downgrade would also increase the fees we pay on our various credit facilities, thus increasing the cost of our working capital. A rating downgrade could also impact our ability to grow our businesses by substantially increasing the cost of, or limiting access to, capital. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. As a result, FirstEnergy may be required to post up to $48 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. On September 28, 2010, S&P then affirmed the ratings and stable outlook of FE and its subsidiaries. On December 15, 2010, Fitch revised its outlook on FE and FES from stable to negative and affirmed the rating for FirstEnergy and its subsidiaries.
A rating is not a recommendation to buy, sell or hold debt, inasmuch as such rating does not comment as to market price or suitability for a particular investor. The ratings assigned to our debt address the likelihood of payment of principal and interest pursuant to their terms. A rating may be subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating that may be assigned to our securities. Also, we cannot predict how rating agencies may modify their evaluation process or the impact such a modification may have on our ratings.
Our credit ratings also govern the collateral provisions of certain contract guarantees. Subsequent to the occurrence of a credit rating downgrade to below investment grade or a “material adverse event,” the immediate posting of cash collateral may be required. See Note 15(B) of the Notes to the Consolidated Financial Statements for more information associated with a credit ratings downgrade leading to the posting of cash collateral.
We Must Rely on Cash from Our Subsidiaries and Any Restrictions on Our Utility Subsidiaries’ Ability to Pay Dividends or Make Cash Payments to Us May Adversely Affect Our Financial Condition
We are a holding company and our investments in our subsidiaries are our primary assets. Substantially all of our business is conducted by our subsidiaries. Consequently, our cash flow is dependent on the operating cash flows of our subsidiaries and their ability to upstream cash to the holding company. Our utility subsidiaries are regulated by various state utility commissions that generally possess broad powers to ensure that the needs of utility customers are being met. Those state commissions could attempt to impose restrictions on the ability of our utility subsidiaries to pay dividends or otherwise restrict cash payments to us.
We Cannot Assure Common Shareholders that Future Dividend Payments Will be Made, or if Made, in What Amounts they May be Paid
Our Board of Directors regularly evaluates our common stock dividend policy and determines the dividend rate each quarter. The level of dividends will continue to be influenced by many factors, including, among other things, our earnings, financial condition and cash flows from subsidiaries, as well as general economic and competitive conditions. We cannot assure common shareholders that dividends will be paid in the future, or that, if paid, dividends will be at the same amount or with the same frequency as in the past.
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Disruptions in the Capital and Credit Markets May Adversely Affect Our Business, Including the Availability and Cost of Short-Term Funds for Liquidity Requirements, Our Ability to Meet Long-Term Commitments, Our Ability to Hedge Effectively Our Generation Portfolio, and the Competitiveness and Liquidity of Energy Markets; Each Could Adversely Affect Our Results of Operations, Cash Flows and Financial Condition
We rely on the capital markets to meet our financial commitments and short-term liquidity needs if internal funds are not available from our operations. We also use letters of credit provided by various financial institutions to support our hedging operations. Disruptions in the capital and credit markets could adversely affect our ability to draw on our respective credit facilities. Our access to funds under those credit facilities is dependent on the ability of the financial institutions that are parties to the facilities to meet their funding commitments. Those institutions may not be able to meet their funding commitments if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time.
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 adversely affect our access to liquidity needed for our business. Any disruption could require us to take measures to conserve cash until the markets stabilize or until alternative credit arrangements or other funding for our business needs can be arranged. Such measures could include deferring capital expenditures, changing hedging strategies to reduce collateral-posting requirements, and reducing or eliminating future dividend payments or other discretionary uses of cash.
The strength and depth of competition in energy markets depends heavily on active participation by multiple counterparties, which could be adversely affected by disruptions in the capital and credit markets. 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 our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace those 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 our results of operations and cash flows.
Questions Regarding the Soundness of Financial Institutions or Counterparties Could Adversely Affect Us
We have exposure to many different financial institutions and counterparties and we routinely execute transactions with counterparties in connection with our hedging activities, including brokers and dealers, commercial banks, investment banks and other institutions and industry participants. Many of these transactions expose us to credit risk in the event that any of our lenders or counterparties are unable to honor their commitments or otherwise default under a financing agreement. We also deposit cash balances in short-term investments. Our ability to access our cash quickly depends on the soundness of the financial institutions in which those funds reside. Any delay in our ability to access those funds, even for a short period of time, could have a material adverse effect on our results of operations and financial condition.
| ITEM 1B. | UNRESOLVED STAFF COMMENTS |
None.
| ITEM 2. | PROPERTIES |
The Utilities’ (other than ATSI and JCP&L), FGCO’s and NGC’s respective first mortgage indentures constitute, in the opinion of their counsel, direct first liens on substantially all of the respective Utilities’, FGCO’s and NGC’s physical property, subject only to excepted encumbrances, as defined in the first mortgage indentures. See the “Leases” and “Capitalization” notes to the respective financial statements for information concerning leases and financing encumbrances affecting certain of the Utilities’, FGCO’s and NGC’s properties.
FirstEnergy controls the following generation sources as of January 31, 2011, shown in the table below. Except for the leasehold interests, OVEC participation and purchased wind power referenced in the footnotes to the table, substantially all of the generating units are owned by NGC (nuclear) and FGCO (non-nuclear).
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| Net Demonstrated | ||||||||
| Plant-Location | Unit | Capacity (MW) | ||||||
| Coal-Fired Units | ||||||||
| Ashtabula- | ||||||||
| Ashtabula, OH | 5 | 244 | ||||||
| Bay Shore- | ||||||||
| Toledo, OH | 1-4 | 631 | ||||||
| R. E. Burger- | ||||||||
| Shadyside, OH | 3 | 94 | ||||||
| Eastlake-Eastlake, OH | 1-5 | 1,233 | ||||||
| Lakeshore- | ||||||||
| Cleveland, OH | 18 | 245 | ||||||
| Bruce Mansfield- | 1 | 830 | (a) | |||||
| Shippingport, PA | 2 | 830 | (b) | |||||
| 3 | 830 | (c) | ||||||
| W. H. Sammis — Stratton, OH | 1-7 | 2,220 | ||||||
| Kyger Creek — Cheshire, OH | 1-5 | 50 | (d) | |||||
| Clifty Creek — Madison, IN | 1-6 | 60 | (d) | |||||
| Total | 7,267 | |||||||
| Nuclear Units | ||||||||
| Beaver Valley- | 1 | 911 | ||||||
| Shippingport, PA | 2 | 904 | (e) | |||||
| Davis-Besse- | ||||||||
| Oak Harbor, OH | 1 | 908 | ||||||
| Perry- | ||||||||
| N. Perry Village, OH | 1 | 1,268 | (f) | |||||
| Total | 3,991 | |||||||
| Oil/Gas — Fired/ | ||||||||
| Pumped Storage Units | ||||||||
| Richland — Defiance, OH | 1-6 | 432 | ||||||
| Seneca — Warren, PA | 1-3 | 451 | ||||||
| West Lorain — Lorain, OH | 1-6 | 545 | ||||||
| Yard’s Creek — Blairstown | ||||||||
| Twp., NJ | 1-3 | 200 | (g) | |||||
| Wind power | 376 | (h) | ||||||
| Other | 174 | |||||||
| Total | 2,178 | |||||||
| Grand Total | 13,436 | |||||||
| (a) | Includes FGCO’s leasehold interest of 93.825% (779 MW) and CEI’s leasehold interest of 6.175% (51 MW), which has been assigned to FGCO. | |
| (b) | Includes CEI’s and TE’s leasehold interests of 27.17% (226 MW) and 16.435% (136 MW), respectively, which have been assigned to FGCO. | |
| (c) | Includes CEI’s and TE’s leasehold interests of 23.247% (193 MW) and 18.915% (157 MW), respectively, which have been assigned to FGCO. | |
| (d) | Represents FGCO’s 4.85% entitlement based on its participation in OVEC. | |
| (e) | Includes OE’s leasehold interest of 16.65% (151 MW) from non-affiliates. | |
| (f) | Includes OE’s leasehold interest of 8.11% (103 MW) from non-affiliates. | |
| (g) | Represents JCP&L’s 50% ownership interest. | |
| (h) | Includes 167 MW from leased facilities and 209 MW under power purchase agreements. |
The above generating plants and load centers are connected by a transmission system consisting of elements having various voltage ratings ranging from 23 kV to 500 kV. The Utilities’ overhead and underground transmission lines aggregate 14,932 pole miles.
The Utilities’ electric distribution systems include 194,685 miles of overhead pole line and underground conduit carrying primary, secondary and street lighting circuits. They own substations with a total installed transformer capacity of 85,247,000 kV-amperes.
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The transmission facilities that are owned by ATSI are currently operated on an integrated basis as part of MISO through May 31, 2011. Effective June 1, 2011, the ATSI transmission assets will be migrated from MISO and integrated into PJM. The transmission facilities of JCP&L, Met-Ed and Penelec are physically interconnected and are operated on an integrated basis as part of PJM.
FirstEnergy’s distribution and transmission systems as of December 31, 2010, consist of the following:
| Substation | ||||||||||||
| Distribution | Transmission | Transformer | ||||||||||
| Lines | Lines | Capacity** | ||||||||||
| OE | 62,156 | 461 | 8,300,000 | |||||||||
| Penn | 13,389 | 52 | 1,351,000 | |||||||||
| CEI | 33,210 | — | 8,754,000 | |||||||||
| TE | 17,592 | 81 | 2,497,000 | |||||||||
| JCP&L | 22,668 | 2,549 | 20,078,000 | |||||||||
| Met-Ed | 18,641 | 1,405 | 8,595,000 | |||||||||
| Penelec | 27,029 | 2,860 | 12,409,000 | |||||||||
ATSI* | — | 7,524 | 23,263,000 | |||||||||
| Total | 194,685 | 14,932 | 85,247,000 | |||||||||
| * | Represents transmission lines of 69kV and above located in the service areas of OE, Penn, CEI and TE. | |
| ** | Top rating of in-service power transformers only. Excludes grounding banks, station power transformers, and generator and customer-owned transformers. |
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| ITEM 3. | LEGAL PROCEEDINGS |
Reference is made to Note 14, Commitments, Guarantees and Contingencies, of FirstEnergy’s Notes to Consolidated Financial Statements contained in Item 8 for a description of certain legal proceedings involving FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
| ITEM 4. | REMOVED AND RESERVED |
PART II
| ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES |
The information required by Item 5 regarding FirstEnergy’s market information, including stock exchange listings and quarterly stock market prices, dividends and holders of common stock is included in Item 6.
Information for FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec is not disclosed because they are wholly owned subsidiaries of FirstEnergy and there is no market for their common stock.
Information regarding compensation plans for which shares of FirstEnergy common stock may be issued is incorporated herein by reference to FirstEnergy’s 2011 proxy statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the fourth quarter of 2010.
| Period | ||||||||||||||||
| October | November | December | Fourth Quarter | |||||||||||||
Total Number of Shares Purchased(a) | 68,246 | 133,762 | 539,703 | 741,711 | ||||||||||||
| Average Price Paid per Share | $ | 38.50 | $ | 35.99 | $ | 35.48 | $ | 35.85 | ||||||||
| Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs | — | — | — | — | ||||||||||||
| Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs | — | — | — | — | ||||||||||||
| (a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan. |
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| ITEM 6. | SELECTED FINANCIAL DATA |
| For the Years Ended December 31, | 2010 | 2009 | 2008 | 2007 | 2006 | |||||||||||||||
| (In millions, except per share amounts) | ||||||||||||||||||||
| Revenues | $ | 13,339 | $ | 12,973 | $ | 13,627 | $ | 12,802 | $ | 11,501 | ||||||||||
| Income From Continuing Operations | $ | 784 | $ | 1,006 | $ | 1,342 | $ | 1,309 | $ | 1,258 | ||||||||||
| Earnings Available to FirstEnergy Corp. | $ | 784 | $ | 1,006 | $ | 1,342 | $ | 1,309 | $ | 1,254 | ||||||||||
| Basic Earnings per Share of Common Stock: | ||||||||||||||||||||
| Income from continuing operations | $ | 2.58 | $ | 3.31 | $ | 4.41 | $ | 4.27 | $ | 3.85 | ||||||||||
| Earnings per basic share | $ | 2.58 | $ | 3.31 | $ | 4.41 | $ | 4.27 | $ | 3.84 | ||||||||||
| Diluted Earnings per Share of Common Stock: | ||||||||||||||||||||
| Income from continuing operations | $ | 2.57 | $ | 3.29 | $ | 4.38 | $ | 4.22 | $ | 3.82 | ||||||||||
| Earnings per diluted share | $ | 2.57 | $ | 3.29 | $ | 4.38 | $ | 4.22 | $ | 3.81 | ||||||||||
Dividends Declared per Share of Common Stock(1) | $ | 2.20 | $ | 2.20 | $ | 2.20 | $ | 2.05 | $ | 1.85 | ||||||||||
| Total Assets | $ | 34,805 | $ | 34,304 | $ | 33,521 | $ | 32,311 | $ | 31,196 | ||||||||||
| Capitalization as of December 31: | ||||||||||||||||||||
| Total Equity | $ | 8,513 | $ | 8,557 | $ | 8,315 | $ | 9,007 | $ | 9,069 | ||||||||||
| Long-Term Debt and Other Long-Term Obligations | 12,579 | 12,008 | 9,100 | 8,869 | 8,535 | |||||||||||||||
| Total Capitalization | $ | 21,092 | $ | 20,565 | $ | 17,415 | $ | 17,876 | $ | 17,604 | ||||||||||
| Weighted Average Number of Basic Shares Outstanding | 304 | 304 | 304 | 306 | 324 | |||||||||||||||
| Weighted Average Number of Diluted Shares Outstanding | 305 | 306 | 307 | 310 | 327 | |||||||||||||||
| (1) | Dividends declared in 2010, 2009 and 2008 include four quarterly dividends of $0.55 per share. Dividends declared in 2007 include three quarterly payments of $0.50 per share in 2007 and one quarterly payment of $0.55 per share in 2008. Dividends declared in 2006 include three quarterly payments of $0.45 per share in 2006 and one quarterly payment of $0.50 per share in 2007. |
PRICE RANGE OF COMMON STOCK
The common stock of FirstEnergy Corp. is listed on the New York Stock Exchange under the symbol “FE” and is traded on other registered exchanges.
| 2010 | 2009 | |||||||||||||||
| First Quarter High-Low | $ | 47.09 | $ | 38.31 | $ | 53.63 | $ | 35.63 | ||||||||
| Second Quarter High-Low | $ | 39.96 | $ | 33.57 | $ | 43.29 | $ | 35.26 | ||||||||
| Third Quarter High-Low | $ | 39.06 | $ | 34.51 | $ | 47.82 | $ | 36.73 | ||||||||
| Fourth Quarter High-Low | $ | 40.12 | $ | 35.00 | $ | 47.77 | $ | 41.57 | ||||||||
| Yearly High-Low | $ | 47.09 | $ | 33.57 | $ | 53.63 | $ | 35.26 | ||||||||
Prices are from http://finance.yahoo.com.
SHAREHOLDER RETURN
The following graph shows the total cumulative return from a $100 investment on December 31, 2005 in FirstEnergy’s common stock compared with the total cumulative returns of EEI’s Index of Investor-Owned Electric Utility Companies and the S&P 500.
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HOLDERS OF COMMON STOCK
There were 105,822 and 105,518 holders of 304,835,407 shares of FirstEnergy’s common stock as of December 31, 2010 and January 31, 2011, respectively. Information regarding retained earnings available for payment of cash dividends is given in Note 11 to the consolidated financial statements.
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| ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF REGISTRANT AND SUBSIDIARIES |
Forward-Looking Statements:This Form 10-K includes forward-looking statements based on information currently available to management. Such statements are subject to certain risks and uncertainties. These statements include declarations regarding management’s intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
| • | The speed and nature of increased competition in the electric utility industry. |
| • | The impact of the regulatory process on the pending matters in the various states in which we do business. |
| • | Business and regulatory impacts from ATSI’s realignment into PJM Interconnection, L.L.C., economic or weather conditions affecting future sales and margins. |
| • | Changes in markets for energy services. |
| • | Changing energy and commodity market prices and availability. |
| • | Financial derivative reforms that could increase our liquidity needs and collateral costs, replacement power costs being higher than anticipated or inadequately hedged. |
| • | The continued ability of FirstEnergy’s regulated utilities to collect transition and other costs. |
| • | Operation and maintenance costs being higher than anticipated. |
| • | Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission and coal combustion residual regulations. |
| • | The potential impacts of any laws, rules or regulations that ultimately replace CAIR. |
| • | The uncertainty of the timing and amounts of the capital expenditures needed to resolve any NSR litigation or other potential similar regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units). |
| • | Adverse regulatory or legal decisions and outcomes (including, but not limited to, the revocation of necessary licenses or operating permits and oversight) by the NRC. |
| • | Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s transmission service charge appeal at the Commonwealth Court of Pennsylvania. |
| • | Any impact resulting from the receipt by Signal Peak of the Department of Labor’s notice of a potential pattern of violations at Bull Mountain Mine No.1. |
| • | The continuing availability of generating units and their ability to operate at or near full capacity. |
| • | The ability to comply with applicable state and federal reliability standards and energy efficiency mandates. |
| • | Changes in customers’ demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates. |
| • | The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives). |
| • | The ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins and the ability to experience growth in the distribution business. |
| • | The changing market conditions that could affect the value of assets held in the registrants’ nuclear decommissioning trusts, pension trusts and other trust funds, and cause FirstEnergy to make additional contributions sooner, or in amounts that are larger than currently anticipated. |
| • | The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’s financing plan and the cost of such capital. |
| • | Changes in general economic conditions affecting the registrants. |
| • | The state of the capital and credit markets affecting the registrants. |
| • | Interest rates and any actions taken by credit rating agencies that could negatively affect the registrants’ access to financing or their costs and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees. |
| • | The continuing uncertainty of the national and regional economy and its impact on the registrants’ major industrial and commercial customers. |
| • | Issues concerning the soundness of financial institutions and counterparties with which the registrants do business. |
| • | The expected timing and likelihood of completion of the proposed merger with Allegheny, including the timing, receipt and terms and conditions of any required governmental and regulatory approvals of the proposed merger that could reduce anticipated benefits or cause the parties to abandon the merger, the diversion of management’s time and attention from FirstEnergy’s ongoing business during this time period, the ability to maintain relationships with customers, employees or suppliers as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect. |
| • | The risks and other factors discussed from time to time in the registrants’ SEC filings, and other similar factors. |
Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations. The foregoing review of factors should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on the registrants’ business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or otherwise.
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FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. in 2010 were $784 million, or basic earnings of $2.58 per share of common stock ($2.57 diluted), compared with $1.01 billion, or basic earnings of $3.31 per share of common stock ($3.29 diluted), in 2009 and $1.34 billion, or basic earnings of $4.41 per share ($4.38 diluted), in 2008.
| Change in Basic Earnings Per Share From Prior Year | 2010 | 2009 | ||||||
| Basic Earnings Per Share — Prior Year | $ | 3.31 | $ | 4.41 | ||||
| Non-core asset sales/impairments | (0.37 | ) | 0.47 | |||||
| Generating plant impairments | (0.77 | ) | — | |||||
| Litigation settlement | 0.04 | (0.03 | ) | |||||
| Trust securities impairments | 0.03 | 0.16 | ||||||
| Regulatory charges | 0.45 | (0.55 | ) | |||||
| Derivative mark-to-market adjustment | 0.35 | (0.42 | ) | |||||
| Organizational restructuring | 0.14 | (0.14 | ) | |||||
| Debt redemption premium | 0.32 | (0.31 | ) | |||||
| Merger transaction costs — 2010 | (0.16 | ) | — | |||||
| Income tax resolution | (0.57 | ) | 0.68 | |||||
| Revenues | 1.06 | (1.85 | ) | |||||
| Fuel and purchased power | (0.68 | ) | (0.09 | ) | ||||
| Amortization of regulatory assets, net | 0.22 | (0.02 | ) | |||||
| Investment income | (0.20 | ) | 0.20 | |||||
| Interest expense | — | (0.14 | ) | |||||
| Transmission expense | (0.20 | ) | 0.73 | |||||
| Other expenses | (0.39 | ) | 0.21 | |||||
| Basic Earnings Per Share | $ | 2.58 | $ | 3.31 | ||||
2010 was a transformational year for FirstEnergy, and one in which we built a strong foundation for future success.
On February 11, 2010, FirstEnergy and Allegheny announced a proposed merger that would create the nation’s largest electric utility system, with:
| • | more than 6 million customers across ten regulated electric distribution subsidiaries in Ohio, Pennsylvania, New Jersey, Maryland and West Virginia, |
| • | generation subsidiaries owning or controlling approximately 24,000 MWs of generating capacity from a diversified mix of coal, nuclear, natural gas, oil and renewable power, and |
| • | transmission subsidiaries owning over 20,000 miles of high-voltage lines connecting the Midwest and Mid-Atlantic. |
Pursuant to the terms of the merger, Allegheny shareholders would receive 0.667 of a share of FirstEnergy common stock in exchange for each share of Allegheny they own.
2010 also marked FirstEnergy’s final transition year to competitive markets with the expiration of the rate cap on Met-Ed and Penelec’s retail generation rates on December 31, 2010. Beginning in 2011, Met-Ed and Penelec obtain their power supply from the competitive wholesale market and fully recover their generation costs through retail rates. All of FirstEnergy’s other regulated utilities previously transitioned to competitive generation markets.
The effects of the uncertainty in the U.S. economy continue to present challenges. Although economic recovery began across our service territories, power sales and deliveries have still not returned to pre-recessionary levels. Distribution deliveries in 2010 were 108.0 million MWH, compared with 102.3 million MWH in 2009, driven primarily by an 8.4% increase in deliveries to the industrial sector, with the largest gains from customers in the automotive and steel industries. Industrial usage is lagging pre-recessionary levels by approximately 11%. Residential sales were up 6%, primarily due to warmer weather during the summer of 2010. Wholesale power prices continued to be weak; however, generation output improved in 2010 with output of 74.9 million MWH compared to the 2009 output of 65.6 million MWH.
In the second half of 2010, FES entered into financial transactions that offset the mark-to-market impact of 500 MW of legacy purchased power contracts which were entered into in 2008 for delivery in 2010 and 2011 and which were marked to market beginning in December 2009. These financial transactions eliminate the volatility in GAAP earnings associated with marking these contracts to market through the end of 2011.
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FES continued implementation of its retail strategy by focusing on direct, governmental aggregation and POLR sales opportunities. As of February 8, 2011, FES committed sales (as a percentage of total projected sales) for 2011 and 2012 were 96% and 65% respectively.
Operational Matters
PJM RTO Integration
In March 2010 two FRR Integration Auctions were conducted by PJM on behalf of the Ohio Companies to secure electric capacity for delivery years June 1, 2011, through May 31, 2012, and June 1, 2012, through May 31, 2013. In the 2011/2012 auction, 27 suppliers participated and 12,583 MW of unforced capacity (the MW bid into the auction after adjusting for historical forced outage rates) cleared at a price of $108.89/MW-day. The 2012/2013 auction had 28 market participants, with 13,038 MW of unforced capacity clearing at a price of $20.46/MW-day. FirstEnergy plans to integrate its operations into PJM by June 1, 2011.
Nuclear Generation
On February 28, 2010, the Davis-Besse Nuclear Plant (908 MW) shut down for its 16th scheduled refueling outage to exchange 76 of 177 fuel assemblies and to conduct numerous safety inspections. During the outage, it was determined through testing that modification work also needed to be performed on certain CRDM nozzles that penetrate the reactor vessel head. Modifications of 24 of the 69 nozzles on the reactor head were completed and Davis-Besse returned to service on June 29, 2010. The plant was originally scheduled to have a new reactor vessel head installed in 2014. This timeline was voluntarily accelerated, and FirstEnergy plans to install the new reactor head in the fall of 2011.
On August 30, 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license. In a letter dated October 18, 2010, the NRC determined that the Davis-Besse license renewal application was complete and acceptable for docketing and further review. Davis-Besse currently is licensed until 2017; if approved, the renewal would extend operations for an additional 20 years, until 2037.
On October 2, 2010, Beaver Valley Nuclear Power Station Unit 1 (911 MW) began its scheduled refueling and maintenance outage. During the outage FENOC exchanged 60 of the 157 fuel assemblies, conducted safety inspections and performed routine maintenance work. The plant returned to service on November 4, 2010.
Coal and Gas Fired Generation
On March 31, 2010, FGCO closed the sale of its 340 MW Sumpter Plant in Sumpter, Michigan, to Wolverine Power Supply Cooperative, Inc. FirstEnergy recorded a $6 million impairment of the Sumpter plant in December 2009 and a loss of $9 million with the sale in the first quarter of 2010. The plant consists of four 85 MW natural gas turbines and represented FirstEnergy’s only generation assets in Michigan.
On August 12, 2010, FirstEnergy announced that operational changes would be made to some of the smaller coal-fired units in response to the slow economy, the lower demand for electricity and uncertainty related to proposed new federal environmental regulations. Beginning September 2010, Bay Shore units 2-4, Eastlake units 1-4, the Lake Shore Plant, and the Ashtabula Plant, which total 1,620 MW of capacity, began operating with minimum three-day notice and in response to consumer demand. FGCO recognized an impairment of $303 million ($190 million after tax) related to these assets in 2010.
On November 17, 2010, we announced plans to cancel repowering Units 4 and 5 (312 MW) at the R.E. Burger Plant to generate electricity principally with biomass. FGCO recognized an impairment of $72 million ($45 million after tax) and permanently shut down these units on December 31, 2010, due to the current market conditions.
During the third quarter of 2010, FGCO re-evaluated the schedule for completing the Fremont Plant (707 MW) due to market conditions and the extension of the tax incentives included in the Small Business legislation through 2011. As a result, FGCO extended the plant’s expected completion to December 31, 2011, to reduce overtime labor cost and outside contractor spend for the remainder of the project. On February 3, 2011, FirstEnergy and American Municipal Power, Inc., entered into a non-binding Memorandum of Understanding (MOU) for the sale of our Fremont Energy Center. The MOU provides, among other things, for the parties to engage in exclusive negotiations towards a definitive agreement expected to be executed in March, 2011, with a targeted closing date in July, 2011.
On December 28, 2010, FirstEnergy closed the sale of 6.65% of FGCO’s participation interest in the output of OVEC (approximately 150 MW) to Peninsula Generation Cooperative, a subsidiary of Wolverine Power Supply Cooperative, Inc., effective December 31, 2010. FirstEnergy’s remaining interest in OVEC is 4.85%. The gain from this transaction increased 2010 net income by $53.8 million.
The Signal Peak coal mining operation in Montana, a joint venture owned 50% by FirstEnergy, began production in December 2009, providing FirstEnergy flexibility with respect to coal commodity supply for its fossil generation fleet. As part of this transaction, we also entered into a 15-year agreement to purchase up to 10 million tons of coal annually from the mine, securing a long-term western fuel supply at attractive prices. Signal Peak provides us with optionality — to either burn its western coal in our units, or sell the coal through the venture to other domestic or international buyers.
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Finally, in 2010 we completed a $1.8 billion environmental retrofit of the W.H. Sammis Plant in Stratton, Ohio. This project was designed to reduce SO2 emissions by 95% at the plant and NOx emissions by 90% at its two largest units. This project was among the largest AQC retrofits ever completed in the United States.
Ohio Wind Power Project
On February 8, 2011, FES announced its agreement to purchase 100 MW of output from Blue Creek Wind Farm (304 MW), which is being built in western Ohio by Iberdrola Renewables. Under terms of the agreement FES will purchase 100 MW of the total output of the project for 20 years beginning in October 2012.
Financial Matters
Cash flow from operations in 2010 was at a record level of $3.1 billion. During the year we also completed refinancing $725 million of variable rate debt to fixed rate debt.
In April and June of 2010, FGCO, a subsidiary of FES, purchased $235 million of variable rate PCRBs and $15 million of fixed rate PCRBs, respectively, originally issued on its behalf. In August of 2010, FES completed the remarketing of the $250 million of PCRBs; $235 million were successfully converted from a variable interest rate to a fixed interest rate and the remaining $15 million of PCRBs remain in a fixed rate mode. The $235 million series now bears a per-annum rate of 2.25% and is subject to mandatory purchase on June 3, 2013. The $15 million series now bears a per-annum rate of 1.5% and is subject to mandatory purchase on June 1, 2011.
Subsequently, in October of 2010, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These series were converted from a variable interest rate to a fixed interest rate of 3.375% per-annum and are subject to mandatory purchase on July 1, 2015. On December 3, 2010, FES and Penelec completed the refinancing and remarketing of five series of PCRBs totaling $178 million. These series were converted from variable rate to fixed interest rates ranging from 2.25% to 3.75% per-annum and are subject to mandatory purchase.
In May of 2010, FirstEnergy terminated fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $43.1 million. As of June 30, 2010, the debt underlying the $3.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 6%, which the swaps converted to a current weighted average variable rate of 4%. On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements resulting in cash proceeds of $83.6 million. The related gain from both of those transactions will generally be amortized to earnings over the life of the underlying debt. As of December 31, 2010, there were no fixed-to-floating swaps hedging the consolidated interest rate risk associated with FirstEnergy’s consolidated debt.
On June 1, 2010, Penn redeemed $1 million of 5.40% PCRBs, due 2013, and on July 30, 2010, redeemed $6.5 million of its 7.65% FMBs due in 2023.
On October 22, 2010, Signal Peak Energy and Global Rail Group, as borrowers, entered into a new $350 million senior secured term loan facility. The two-year syndicated bank loan is guaranteed by FirstEnergy and the other owners of the borrowers. The proceeds from the loan were used to repay bank borrowings ($63 million) and debt owed to FirstEnergy ($258 million) with the balance to be used for other general corporate purposes.
In February 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. These rating agency actions were taken in response to the announcement of the proposed merger with Allegheny. On September 28, 2010 S&P affirmed the ratings and stable outlook of FE and its subsidiaries. On December 15, 2010, Fitch revised its outlook on FirstEnergy and FES from stable to negative and affirmed the rating for FirstEnergy and its subsidiaries.
Regulatory Matters
Ohio ESP
The Ohio Companies will be operating under a new ESP effective June 1, 2011 through May 31, 2014, which was filed in March 2010 and approved by the PUCO in August 2010. That ESP provides customers with no overall increase to base distribution rates during the plan period and limits the costs they will pay related to certain PJM transmission projects. The ESP provides the Ohio Companies with recovery of capital invested in their distribution businesses through a Delivery Capital Recovery Rider effective January 1, 2012, through May 31, 2014. Generation rates for the annual delivery periods during the plan are determined through a CBP which will be conducted every October and January for generation service through May 31, 2014. The first two CBPs were conducted in October 2010 and January 2011. Both auctions consisted of one, two and three-year products. The results of these auctions were accepted by the PUCO. The next auction is scheduled for October 2011.
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Pennsylvania Default Service Plan
On October 20, 2010, the PPUC approved the results of various auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. The auction was the last of four auctions for the five-month period of January 1, 2011 to May 31, 2011, and the second of four auctions to procure commercial default service requirements for the 12-month period of June 1, 2011 to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011 to May 31, 2013. The PPUC also approved the default service RFP for the Residential Fixed Block On-Peak and Off-Peak energy products. On January 18-20, 2011, Met-Ed, Penelec and Penn conducted auctions to procure a portion of the default service requirements for their customers who choose not to shop with an alternative supplier. The January 2011 auction was the third of four auctions for Met-Ed and Penelec and the first of two auctions for Penn to procure commercial default service requirements for the 12-month period of June 1, 2011 to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011 to May 31, 2013. For Met-Ed, Penelec and Penn commercial customers the tranche-weighted average price ($/MWH) was $69.97, $59.32 and $57.88, respectively, and for residential customers the tranche-weighted average price was $70.69, $59.74 and $55.39, respectively. This was also the first of two auctions held to procure residential service requirements for the 12-month period of June 1, 2011 to May 31, 2012. For Met-Ed, Penelec and Penn residential customers the tranche-weighted average price ($/MWH) was $67.43, $58.01 and $60.29, respectively. In addition, the January 2011 auction procured supply for Met-Ed and Penelec industrial customers Hourly Priced Default Service. For Met-Ed and Penelec, the average 12-month price ($/MWH) was $9.90 and $9.91, respectively. The PPUC approved the results of the January 2011 auctions on January 24, 2011.
Penn Power’s settlement for approval of its Default Service Plan for the period of June 1, 2011 through May 31, 2013 was approved by the PPUC on October 21, 2010. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn's June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Energy Efficiency, Smart Grid and Smart Meter Programs
On June 3, 2010, FirstEnergy and the DOE signed grants totaling $57.4 million that were awarded as part of the American Recovery and Reinvestment Act to introduce smart grid technologies in targeted areas in Pennsylvania, Ohio, and New Jersey. The DOE grants represent 50% of the funding for approximately $115 million FirstEnergy plans to invest in smart grid technologies. The PPUC, PUCO and NJBPU have approved recovery of the remaining costs not funded through the DOE grant for the smart grid programs in Pennsylvania, Ohio and New Jersey, respectively, and the programs are underway in all three states.
Pennsylvania’s Act 129 (Act 129) requires all Pennsylvania electric distribution companies with more than 100,000 customers to install smart meter technology within 15 years. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision issued on January 28, 2010 and decided various issues regarding the SMIP for the Pennsylvania Companies. An order consistent with Chairman Cawley’s Motion was entered on June 9, 2010. The companies filed a petition for reconsideration on a single portion of the order, and on August 5, 2010, the PPUC entered an order granting in part the petition for reconsideration. The Pennsylvania Companies’ SMIP will assess the technologies, vendors, capital cost, and potential benefits of smart meter technology during an assessment period that covers the next 24 months. The Pennsylvania Companies expect to incur approximately $29.5 million of costs during the assessment period which they expect to recover through the Smart Meter Technologies Charge rider. At the end of the assessment period, the Pennsylvania Companies will submit to the PPUC a deployment plan for the full scale deployment of smart meters. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
Act 129 also requires utilities to reduce energy consumption and peak demand, with electricity consumption reduction targets of 1% by May 31, 2011, and 3% by May 31, 2013, and a peak demand reduction target of 4.5% by May 31, 2013. The Pennsylvania Companies responded by offering a wide variety of programs to residential, commercial, industrial, governmental and non-profit customers through their PPUC-approved EE&C Plans.
JCP&L Rate Adjustment
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2010, the accumulated deferred cost balance was a credit of approximately $37 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. On February 10, 2011, the NJBPU approved a stipulation which allows the change in rates to become effective March 1, 2011.
On January 18, 2011, JCP&L provided information to the NJBPU regarding the proposed merger between FirstEnergy and Allegheny. A stipulation between JCP&L, Board Staff and Rate Counsel was also provided. The Board reviewed the Stipulation at its January 25, 2011 meeting and issued an Order on February 10, 2011 indicating that it did not object to the transaction proceeding.
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FIRSTENERGY’S BUSINESS
We are a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).
| • | Energy Delivery Servicestransmits and distributes electricity through our seven utility distribution companies and ATSI, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey. This segment also purchases power for its POLR and default service requirements in all three states. Its revenues are primarily derived from the delivery of electricity within our service areas and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads, and the deferral and amortization of certain fuel costs. |
The service areas of our utilities are summarized below:
| Company | Area Served | Customers Served | ||||
| OE | Central and Northeastern Ohio | 1,037,000 | ||||
| Penn | Western Pennsylvania | 160,000 | ||||
| CEI | Northeastern Ohio | 751,000 | ||||
| TE | Northwestern Ohio | 310,000 | ||||
| JCP&L | Northern, Western and East Central New Jersey | 1,098,000 | ||||
| Met-Ed | Eastern Pennsylvania | 553,000 | ||||
| Penelec | Western Pennsylvania | 591,000 | ||||
| ATSI | Service areas of OE, Penn, CEI and TE | |||||
| • | Competitive Energy Servicessegment supplies electric power to end-use customers through retail and wholesale arrangements primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. This business segment controls 13,236 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers. |
STRATEGY AND OUTLOOK
FirstEnergy’s vision is to be a leading regional energy provider, recognized for operational excellence, outstanding customer service and our commitment to safety; the choice for long-term growth, investment value and financial strength; and a company driven by the leadership, skills, diversity and character of our employees.
Our near-term focus is on getting the merger closed and then successfully managing the merger integration process and capturing long-term value to benefit our customers, shareholders and employees.
The merger integration process is underway and is expected to create significant efficiencies and economies of scale as we share best practices across the new organization. Merger integration teams comprised of employees from both FirstEnergy and Allegheny began working in April 2010 to identify value drivers and estimate transaction benefits.
The proposed merger is a natural geographic fit that would bring together complementary assets and corporate cultures and create a strong company that is well-positioned for growth. Our strength is the diversity of our assets, and our strategic focus is on creating long-term value through our core operations — distribution operations, transmission operations and competitive generation and retail operations.
In our distribution operations, we remain focused on reliability, customer service and safety, and maintaining stable earnings growth. Our combined company will be committed to meeting regulatory expectations and leveraging best practices across seven states and ten operating utilities. FirstEnergy’s management structure and philosophy supports local authority and decision-making by maintaining a local presence, which includes regional offices for our utility operations.
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Presently, our competitive generation portfolio of 13,236 MW contains a diverse mix of quality assets, including nuclear, coal, natural gas, wind and pumped storage.
In response to reduced customer demand and uncertainty related to proposed new federal environmental regulations, FirstEnergy announced in August 2010 operational changes at several fossil plants. Affected are nine units at four plants located on the shore of Lake Erie in Ohio, with 1,620 MW of total capacity. In September 2010, the units began operating with a minimum three-day notice and in response to customer demand. These operational changes provide future flexibility regarding potential plant retirements given the current ongoing uncertainty regarding future EPA mandates or environmental legislation. (see Environmental Outlook below). We plan to make a similar evaluation of Allegheny’s fossil assets once the merger is completed; however, because most of Allegheny’s supercritical units have already been retrofitted with environmental control equipment, it is the bulk of their older, regulated subcritical units that are most exposed to potential regulations.
In the fall of 2011, we plan to replace Davis-Besse’s reactor vessel head, accelerating the original replacement scheduled in 2014. We expect this proactive approach to provide additional margins of safety and reliability.
Construction continues on our Fremont Energy Center, which includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. We expect to complete construction of this facility by the end of 2011. On February 3, 2011, FirstEnergy and American Municipal Power, Inc. (AMP), entered into a non-binding Memorandum of Understanding (MOU) for the sale of our Fremont Energy Center. The MOU provides, among other things, for the parties to engage in exclusive negotiations towards a definitive agreement expected to be executed in March, 2011, with a targeted closing date in July, 2011. In addition to Fremont, Signal Peak has been identified as a non-strategic asset that could be made available for sale.
FirstEnergy has identified potential post-merger benefits in the competitive generation and retail business mostly related to expanding the FirstEnergy operating philosophy and model to the combined operation. These include:
| • | Economies of scale and best practices related to fuel procurement and transportation; |
| • | Expanded use of fuel blending techniques; |
| • | Generation asset reliability improvement; |
| • | Dispatch optimization; |
| • | Outage best practices; and |
| • | Expansion of the retail sales growth strategy. |
Our strategy is to sell our own physical generation output to sales channels in close proximity to our fleet at the highest achievable margins. Our retail business remains a key component of our strategy. FES continues to expand its regional reach through retail sales by using its competitive generation assets to back POLR, governmental aggregation and direct sales commitments.
Wholesale power prices remain under pressure in response to continued low gas prices, but we expect future improvements in power prices to benefit the combined fleet.
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Financial Outlook
We remain committed to managing our operating and capital costs in order to achieve our financial goals and commitment to shareholders.
Our liquidity position remains strong, with access to more than $3.2billion of liquidity, of which approximately $3.1 billion was available as of January 31, 2011.
Capital expenditures in 2011 are projected to be $1.4 billion, compared to $1.8 billion in 2010. We intend to continue to fund our capital requirements through cash generated from operations.
Positive earnings drivers for 2011 are expected to include:
| • | Increased retail revenues associated with FES POLR, governmental aggregation and direct sales; |
| • | Reduced fuel expenses; and |
| • | Increased margin from Signal Peak. |
Negative earnings drivers for 2011 are expected to include:
| • | Decreased revenues associated with the expiration of the Met Ed/Penelec partial requirements agreement with FES; |
| • | Increase in net ancillary, congestion, and capacity expenses; |
| • | Increased purchased power expenses; |
| • | Additional planned nuclear outage for Davis-Besse’s reactor head replacement; and |
| • | Increased depreciation expenses and reduced capitalized interest, primarily associated with the Sammis plant environmental project. |
Distribution deliveries and non-fuel, non-outage O&M expenses including employee benefits are expected to be essentially flat in 2011 compared to 2010.
FirstEnergy’s $2.75 billion revolving credit facility matures in August 2012. We intend to review our revolving credit facility needs post-merger and at a minimum anticipate pursuing renewal of the existing facility during the first half of 2011.
In December 2010, a new federal income tax law became effective that provides for bonus depreciation tax benefits. This new law is expected to provide approximately $500 million in additional cash to FirstEnergy through 2012.
We remain focused on liquidity and a strong balance sheet, as well as maintaining investment grade credit ratings. Our financial plan accelerates our goal of improving our financial strength and flexibility by significantly reducing debt by the end of 2012. In addition to cash generated from operations, we expect to deploy cash received through bonus depreciation tax benefits, as well as cash from the future sale of certain non-core assets, to this debt reduction initiative. These actions are expected to improve our credit metrics over the next several years.
Capital Expenditures Outlook
Our capital expenditure forecast for 2011 is projected to be $1.4 billion, which represents a $393 million decrease from 2010.
The main drivers of this decrease are the 2010 completion of the $1.8 billion Sammis AQC environmental compliance project and reduced spending for the Fremont facility, scheduled for completion in 2011.
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Capital expenditures for our competitive energy services business (excluding the AQC project and Fremont facility) are expected to increase slightly in 2011. The primary cause is the previously announced decision to accelerate the replacement of the Davis-Besse nuclear reactor vessel head. This initiative began in 2010 and is expected to be completed in 2011. Other planned generation investments provide for maintenance of critical generation assets, deliver operational improvements to enhance reliability, and support our generation to market strategy.
For our regulated operations, capital expenditures are forecasted at $730 million in 2011. Approximately $100 million has been allocated to the transmission expansion initiative, which includes projects to satisfy transmission capacity and reliability requirements, transitioning to the PJM market, and connecting new load delivery and new wholesale generation points. Expenditures for Ohio and Pennsylvania energy efficiency and advanced metering initiatives are expected to be primarily reimbursed from distribution customers and federal stimulus funding. Other investments for transmission and distribution infrastructure are designed to achieve cost-effective improvements in the reliability of our service.
For 2012 and 2013 we anticipate average annual baseline capital expenditures of approximately $1.2 billion, exclusive of any additional opportunities or future mandated spending. Planned capital initiatives promote reliability, improve operations, and support current environmental and energy efficiency directives.
Actual capital spending for 2010 and projected capital spending for 2011 are as follows:
| Capital Spending by Business Unit | 2010 | 2011 | ||||||
| (In millions) | ||||||||
| Energy Delivery | $ | 729 | $ | 630 | ||||
| Nuclear | 324 | 320 | ||||||
| Fossil | 174 | 160 | ||||||
| FES Other | 21 | 10 | ||||||
| Corporate | 59 | 50 | ||||||
| AQC | 249 | 4 | ||||||
| Baseline Capital Expenditures | $ | 1,556 | $ | 1,174 | ||||
| Fremont Facility | 148 | 56 | ||||||
| Burger Biomass | 7 | — | ||||||
| Transmission Expansion | 79 | 100 | ||||||
| Davis-Besse Reactor Vessel Head Replacement | 23 | 90 | ||||||
| $ | 1,813 | $ | 1,420 | |||||
Environmental Outlook
At FirstEnergy, we continually strive to enhance environmental protection and remain good stewards of our natural resources. We devote significant resources to environmental compliance efforts, and our employees share a commitment to, and accountability for, environmental performance. Our corporate focus on continuous improvement is integral to our environmental programs.
We have spent more than $7 billion on environmental protection efforts since the initial passage of the Clean Air and Water Acts in the 1970s, and these investments are making a difference. Over the past five years, we have invested approximately $1.8 billion at our W.H. Sammis Plant in Stratton, Ohio, to further reduce emissions of SO2 by over 95% and NOx by at least 64%. This is one of the largest environmental retrofit projects in the nation and was recognized by Platts as the 2010 construction project of the year. Since 1990, we have reduced emissions of NOx by more than 83%, SO2 by more than 82%, and mercury by about 60%. Also, our CO2 emission rate, in pounds of CO2 per kWh, has dropped by 19% during this period. Emission rates for our power plants are lower than the regional average.
By the end of 2011, we expect approximately 70% of our generation fleet to be non-emitting or low emitting generation. Over 52% of our coal-fired generating fleet will have full NOx and SO2 equipment controls thus significantly decreasing our exposure to future environmental requirements.
One of the key issues facing our company and industry is global-climate—change-related mandates. Lawmakers at the state and federal levels are exploring and implementing a wide range of responses. We believe our generation fleet is very well positioned to compete in a carbon-constrained economy. In addition, we believe that upon consummation of the proposed merger with Allegheny, our competitive position will be enhanced with an even more diverse mix of fully-scrubbed fossil generation, non-emitting nuclear and renewable generation, including large-scale storage.
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We have taken aggressive steps over the past two decades that have increased our generating capacity without adding to overall CO2 emissions. For example, since 1990, we have reconfigured our fleet by retiring nearly 1,000 MWs of older, coal-based generation and adding more than 1,800 MWs of non-emitting nuclear capacity. Through these and other actions, we have increased our generating capacity by nearly 15% over the same period while avoiding some 350 million metric tons of CO2 emissions. Today, nearly 40% of our electricity is generated without emitting CO2 — a key advantage that will help us meet the challenge of future governmental climate change mandates. And with recent announcements in 2009, including the expanded use of renewable energy, energy storage and natural gas, our CO2 emission rate will decline even further in the future.
We have taken a leadership role in pursuing new ventures and testing and developing new technologies that show promise in achieving additional reductions in CO2 emissions. These include:
| • | Sales of over 1 million MWH per year of wind generation. |
| • | Testing of CO2 sequestration to gain a better understanding of the potential for geological storage of CO2. |
| • | Supporting afforestation — growing forests on non-forested land — and other efforts designed to remove CO2 from the environment. |
| • | Reducing emissions of SF6 (sulfur hexafluoride) by nearly 15 metric tons, resulting in an equivalent reduction of nearly 315,000 metric tons of CO2, through the EPA’s SF6 Emissions Reduction Partnership for Electric Power Systems. |
| • | Supporting research to develop and evaluate cost effective sorbent materials for CO2 capture including work by Powerspan at the Burger Plant, The University of Akron and the EPRI. |
We remain actively engaged in the federal and state debate over future environmental requirements and legislation, especially those dealing with global climate change, hazardous air pollutants, coal combustion residues and water effluent discharges. We are committed to working with policy makers and regulators to develop fair and reasonable requirements, with the goal of reducing emissions while minimizing the economic impact on our customers. Due to the significant uncertainty as to the final form or timing of any such legislation and regulation at both the federal and state levels, we are unable to determine the potential impact and risks associated with future emissions requirements.
We also have a long history of supporting research in distributed energy resources. Distributed energy resources include fuel cells, solar and wind systems or energy storage technologies located close to the customer or direct control of customer loads to provide alternatives or enhancements to the traditional electric power system. We are testing the world’s largest utility-scale fuel cell system at our Eastlake power plant to determine its feasibility for augmenting generating capacity during summer peak-use periods. Through a partnership with EPRI, the Cuyahoga Valley National Park, the Department of Defense and Case Western Reserve University, two solid-oxide fuel cells were installed as part of a test program to explore the technology and the environmental benefits of distributed generation.
We are also evaluating the impact of distributed energy storage on the distribution system through analysis and field demonstrations of advanced battery technologies. FirstEnergy’s EasyGreen® load-management program utilizes two-way communication capability with customers’ non-critical equipment such as air conditioners in New Jersey and Pennsylvania to help manage peak loading on the electric distribution system. FirstEnergy has also made an online interactive energy efficiency tool, Home Energy Analyzer, available for its customers to help achieve electricity use-reduction goals.
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RISKS AND CHALLENGES
In executing our strategy, we face a number of industry and enterprise risks and challenges, including:
| • | risks arising from the reliability of our power plants and transmission and distribution equipment; |
| • | changes in commodity prices could adversely affect our profit margins; |
| • | we are exposed to operational, price and credit risks associated with selling and marketing products in the power markets that we do not always completely hedge against; | ||
| • | the use of derivative contracts by us to mitigate risks could result in financial losses that may negatively impact our financial results; |
| • | financial derivatives reforms could increase our liquidity needs and collateral costs; |
| • | our risk management policies relating to energy and fuel prices, and counterparty credit, are by their very nature risk related, and we could suffer economic losses despite such policies; |
| • | nuclear generation involves risks that include uncertainties relating to health and safety, additional capital costs, the adequacy of insurance coverage and nuclear plant decommissioning; |
| • | capital market performance and other changes may decrease the value of the decommissioning trust fund, pension fund assets and other trust funds which then could require significant additional funding; |
| • | we could be subject to higher costs and/or penalties related to mandatory reliability standards set by NERC/FERC or changes in the rules of organized markets and the states in which we do business; |
| • | we rely on transmission and distribution assets that we do not own or control to deliver our wholesale electricity. If transmission is disrupted, including our own transmission, or not operated efficiently, or if capacity is inadequate, our ability to sell and deliver power may be hindered; |
| • | disruptions in our fuel supplies could occur, which could adversely affect our ability to operate our generation facilities and impact financial results; |
| • | temperature variations as well as weather conditions or other natural disasters could have a negative impact on our results of operations and demand significantly below or above our forecasts could adversely affect our energy margins; |
| • | we are subject to financial performance risks related to regional and general economic cycles and also related to heavy manufacturing industries such as automotive and steel; |
| • | increases in customer electric rates and economic uncertainty may lead to a greater amount of uncollectible customer accounts; |
| • | the goodwill of one or more of our operating subsidiaries may become impaired, which would result in write-offs of the impaired amounts; |
| • | we face certain human resource risks associated with the availability of trained and qualified labor to meet our future staffing requirements; |
| • | significant increases in our operation and maintenance expenses, including our health care and pension costs, could adversely affect our future earnings and liquidity; |
| • | our business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to our reputation and/or results of operations; |
| • | acts of war or terrorism could negatively impact our business; |
| • | capital improvements and construction projects may not be completed within forecasted budget, schedule or scope parameters; |
| • | changes in technology may significantly affect our generation business by making our generating facilities less competitive; |
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| • | we may acquire assets that could present unanticipated issues for our business in the future, which could adversely affect our ability to realize anticipated benefits of those acquisitions; |
| • | ability of certain FirstEnergy companies to meet their obligations to other FirstEnergy companies; |
| • | our pending merger with Allegheny may not achieve its intended results; |
| • | upon consummation of the pending merger we will be subject to business uncertainties that could adversely affect our financial results; | ||
| • | once the pending merger is closed the combined company will have a higher percentage of coal-fired generation capacity compared to FirstEnergy’s previous generation mix. As a result, FirstEnergy may be exposed to greater risk from regulations of coal and coal combustion by-products than it faced prior to the merger; |
| • | complex and changing government regulations could have a negative impact on our results of operations; |
| • | regulatory changes in the electric industry, including a reversal, discontinuance or delay of the present trend toward competitive markets, could affect our competitive position and result in unrecoverable costs adversely affecting our business and results of operations; |
| • | the prospect of rising rates could prompt legislative or regulatory action to restrict or control such rate increases; this in turn could create uncertainty affecting planning, costs and results of operations and may adversely affect the utilities’ ability to recover their costs, maintain adequate liquidity and address capital requirements; |
| • | our profitability is impacted by our affiliated companies’ continued authorization to sell power at market-based rates; |
| • | there are uncertainties relating to our participation in RTOs; |
| • | a significant delay in or challenges to various elements of ATSI’s consolidation into PJM, including but not limited to, the intervention of parties to the regulatory proceedings could have a negative impact on our results of operations and financial condition; |
| • | energy conservation and energy price increases could negatively impact our financial results; |
| • | our business and activities are subject to extensive environmental requirements and could be adversely affected by such requirements; |
| • | the EPA is conducting NSR investigations at a number of our generating plants, the results of which could negatively impact our results of operations and financial condition; |
| • | costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws, including limitations on GHGemissions could adversely affect cash flow and profitability; |
| • | the physical risks associated with climate change may impact our results of operations and cash flows; |
| • | remediation of environmental contamination at current or formerly owned facilities; |
| • | availability and cost of emission credits could materially impact our costs of operations; |
| • | mandatory renewable portfolio requirements could negatively affect our costs; |
| • | we are and may become subject to legal claims arising from the presence of asbestos or other regulated substances at some of our facilities; |
| • | the continuing availability and operation of generating units is dependent on retaining the necessary licenses, permits, and operating authority from governmental entities, including the NRC; |
| • | future changes in financial accounting standards may affect our reported financial results; |
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| • | increases in taxes and fees; |
| • | interest rates and/or a credit rating downgrade could negatively affect our financing costs, our ability to access capital and our requirement to post collateral; |
| • | we must rely on cash from our subsidiaries and any restrictions on our utility subsidiaries’ ability to pay dividends or make cash payments to us may adversely affect our financial condition; |
| • | we cannot assure common shareholders that future dividend payments will be made, or if made, in what amounts they may be paid; | ||
| • | disruptions in the capital and credit markets may adversely affect our business, including the availability and cost of short-term funds for liquidity requirements, our ability to meet long-term commitments, our ability to hedge effectively our generation portfolio, and the competitiveness and liquidity of energy markets; each could adversely affect our results of operations, cash flows and financial condition; and |
| • | questions regarding the soundness of financial institutions or counterparties could adversely affect us. |
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 15 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:
| Increase (Decrease) | ||||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 vs 2009 | 2009 vs 2008 | ||||||||||||||||
| (In millions, except per share data) | ||||||||||||||||||||
Earnings (Loss) By Business Segment: | ||||||||||||||||||||
| Energy delivery services | $ | 607 | $ | 435 | $ | 916 | $ | 172 | $ | (481 | ) | |||||||||
| Competitive energy services | 258 | 517 | 472 | (259 | ) | 45 | ||||||||||||||
| Other and reconciling adjustments* | (81 | ) | 54 | (46 | ) | (135 | ) | 100 | ||||||||||||
| Total | $ | 784 | $ | 1,006 | $ | 1,342 | $ | (222 | ) | $ | (336 | ) | ||||||||
Basic Earnings Per Share | $ | 2.58 | $ | 3.31 | $ | 4.41 | $ | (0.73 | ) | $ | (1.10 | ) | ||||||||
Diluted Earnings Per Share | $ | 2.57 | $ | 3.29 | $ | 4.38 | $ | (0.72 | ) | $ | (1.09 | ) | ||||||||
| * | Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. |
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Summary of Results of Operations — 2010 Compared with 2009
Financial results for FirstEnergy’s major business segments in 2010 and 2009 were as follows:
| Energy | Competitive | Other and | ||||||||||||||
| Delivery | Energy | Reconciling | FirstEnergy | |||||||||||||
| 2010 Financial Results | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | 9,271 | $ | 3,252 | $ | — | $ | 12,523 | ||||||||
| Other | 542 | 292 | (92 | ) | 742 | |||||||||||
| Internal* | 139 | 2,301 | (2,366 | ) | 74 | |||||||||||
| Total Revenues | 9,952 | 5,845 | (2,458 | ) | 13,339 | |||||||||||
| Expenses: | ||||||||||||||||
| Fuel | — | 1,440 | (8 | ) | 1,432 | |||||||||||
| Purchased power | 5,266 | 1,724 | (2,366 | ) | 4,624 | |||||||||||
| Other operating expenses | 1,492 | 1,436 | (78 | ) | 2,850 | |||||||||||
| Provision for depreciation | 451 | 254 | 41 | 746 | ||||||||||||
| Amortization of regulatory assets | 722 | — | — | 722 | ||||||||||||
| Deferral of new regulatory assets | — | — | — | — | ||||||||||||
| Impairment of long lived assets | — | 384 | — | 384 | ||||||||||||
| General taxes | 653 | 113 | 10 | 776 | ||||||||||||
| Total Expenses | 8,584 | 5,351 | (2,401 | ) | 11,534 | |||||||||||
| Operating Income | 1,368 | 494 | (57 | ) | 1,805 | |||||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | 102 | 51 | (36 | ) | 117 | |||||||||||
| Interest expense | (496 | ) | (221 | ) | (128 | ) | (845 | ) | ||||||||
| Capitalized interest | 5 | 92 | 68 | 165 | ||||||||||||
| Total Other Expense | (389 | ) | (78 | ) | (96 | ) | (563 | ) | ||||||||
| Income Before Income Taxes | 979 | 416 | (153 | ) | 1,242 | |||||||||||
| Income taxes | 372 | 158 | (48 | ) | 482 | |||||||||||
| Net Income (Loss) | 607 | 258 | (105 | ) | 760 | |||||||||||
| Loss attributable to noncontrolling interest | — | — | (24 | ) | (24 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | 607 | $ | 258 | $ | (81 | ) | $ | 784 | |||||||
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. |
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| Energy | Competitive | Other and | ||||||||||||||
| Delivery | Energy | Reconciling | FirstEnergy | |||||||||||||
| 2009 Financial Results | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | 10,585 | $ | 1,447 | $ | — | $ | 12,032 | ||||||||
| Other | 559 | 447 | (82 | ) | 924 | |||||||||||
| Internal* | — | 2,843 | (2,826 | ) | 17 | |||||||||||
| Total Revenues | 11,144 | 4,737 | (2,908 | ) | 12,973 | |||||||||||
| Expenses: | ||||||||||||||||
| Fuel | — | 1,153 | — | 1,153 | ||||||||||||
| Purchased power | 6,560 | 996 | (2,826 | ) | 4,730 | |||||||||||
| Other operating expenses | 1,424 | 1,357 | (84 | ) | 2,697 | |||||||||||
| Provision for depreciation | 445 | 270 | 21 | 736 | ||||||||||||
| Amortization of regulatory assets | 1,155 | — | — | 1,155 | ||||||||||||
| Deferral of new regulatory assets | (136 | ) | — | — | (136 | ) | ||||||||||
| Impairment of long lived assets | — | 6 | — | 6 | ||||||||||||
| General taxes | 641 | 108 | 4 | 753 | ||||||||||||
| Total Expenses | 10,089 | 3,890 | (2,885 | ) | 11,094 | |||||||||||
| Operating Income | 1,055 | 847 | (23 | ) | 1,879 | |||||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | 139 | 121 | (56 | ) | 204 | |||||||||||
| Interest expense | (472 | ) | (166 | ) | (340 | ) | (978 | ) | ||||||||
| Capitalized interest | 3 | 60 | 67 | 130 | ||||||||||||
| Total Other Income (Expense) | (330 | ) | 15 | (329 | ) | (644 | ) | |||||||||
| Income Before Income Taxes | 725 | 862 | (352 | ) | 1,235 | |||||||||||
| Income taxes | 290 | 345 | (390 | ) | 245 | |||||||||||
| Net Income | 435 | 517 | 38 | 990 | ||||||||||||
| Loss attributable to noncontrolling interest | — | — | (16 | ) | (16 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | 435 | $ | 517 | $ | 54 | $ | 1,006 | ||||||||
| * | Under the accounting standard for the effects of certain types of regulation, Internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. |
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| Energy | Competitive | Other and | ||||||||||||||
| Changes Between 2010 and 2009 Financial | Delivery | Energy | Reconciling | FirstEnergy | ||||||||||||
| Results Increase (Decrease) | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | (1,314 | ) | $ | 1,805 | $ | — | $ | 491 | |||||||
| Other | (17 | ) | (155 | ) | (10 | ) | (182 | ) | ||||||||
| Internal* | 139 | (542 | ) | 460 | 57 | |||||||||||
| Total Revenues | (1,192 | ) | 1,108 | 450 | 366 | |||||||||||
| Expenses: | ||||||||||||||||
| Fuel | — | 287 | (8 | ) | 279 | |||||||||||
| Purchased power | (1,294 | ) | 728 | 460 | (106 | ) | ||||||||||
| Other operating expenses | 68 | 79 | 6 | 153 | ||||||||||||
| Provision for depreciation | 6 | (16 | ) | 20 | 10 | |||||||||||
| Amortization of regulatory assets | (433 | ) | — | — | (433 | ) | ||||||||||
| Deferral of new regulatory assets | 136 | — | — | 136 | ||||||||||||
| Impairment of long lived assets | — | 378 | — | 378 | ||||||||||||
| General taxes | 12 | 5 | 6 | 23 | ||||||||||||
| Total Expenses | (1,505 | ) | 1,461 | 484 | 440 | |||||||||||
| Operating Income | 313 | (353 | ) | (34 | ) | (74 | ) | |||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | (37 | ) | (70 | ) | 20 | (87 | ) | |||||||||
| Interest expense | (24 | ) | (55 | ) | 212 | 133 | ||||||||||
| Capitalized interest | 2 | 32 | 1 | 35 | ||||||||||||
| Total Other Expense | (59 | ) | (93 | ) | 233 | 81 | ||||||||||
| Income Before Income Taxes | 254 | (446 | ) | 199 | 7 | |||||||||||
| Income taxes | 82 | (187 | ) | 342 | 237 | |||||||||||
| Net Income | 172 | (259 | ) | (143 | ) | (230 | ) | |||||||||
| Loss attributable to noncontrolling interest | — | — | (8 | ) | (8 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | 172 | $ | (259 | ) | $ | (135 | ) | $ | (222 | ) | |||||
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. |
Energy Delivery Services — 2010 Compared to 2009
Net income increased $172 million to $607 million in 2010 compared to $435 million in 2009, primarily due to CEI’s $216 million regulatory asset impairment in 2009, partially offset by increases in other operating expenses. Lower generation revenues were offset by lower purchased power expenses.
Revenues —
The decrease in total revenues resulted from the following sources:
| Increase | ||||||||||||
| Revenues by Type of Service | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Distribution services | $ | 3,629 | $ | 3,419 | $ | 210 | ||||||
| Generation sales: | ||||||||||||
| Retail | 4,456 | 5,764 | (1,308 | ) | ||||||||
| Wholesale | 841 | 752 | 89 | |||||||||
| Total generation sales | 5,297 | 6,516 | (1,219 | ) | ||||||||
| Transmission | 833 | 1,028 | (195 | ) | ||||||||
| Other | 193 | 181 | 12 | |||||||||
| Total Revenues | $ | 9,952 | $ | 11,144 | $ | (1,192 | ) | |||||
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The increase in distribution deliveries by customer class is summarized in the following table:
| Electric Distribution KWH Deliveries | ||||
| Residential | 5.9 | % | ||
| Commercial | 2.8 | % | ||
| Industrial | 8.4 | % | ||
| Total Distribution KWH Deliveries | 5.6 | % | ||
Higher deliveries to residential and commercial customers reflect increased weather-related usage due to a 70% increase in cooling degree days in 2010 compared to 2009, partially offset by a 4% decrease in heating degree days for the same period. In the industrial sector, KWH deliveries increased primarily to major automotive customers (16%), refinery customers (7%) and steel customers (38%). The increase in distribution service revenues also reflects the Pennsylvania Companies’ recovery of the Pennsylvania EE&C as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
The following table summarizes the price and volume factors contributing to the $1.2 billion decrease in generation revenues in 2010 compared to 2009:
| Increase | ||||
| Source of Change in Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Retail: | ||||
| Effect of 24.9% decrease in sales volumes | $ | (1,438 | ) | |
| Change in prices | 130 | |||
| (1,308 | ) | |||
| Wholesale: | ||||
| Effect of 8.4% decrease in sales volumes | (64 | ) | ||
| Change in prices | 153 | |||
| 89 | ||||
| Net Decrease in Generation Revenues | $ | (1,219 | ) | |
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’ service territories. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries by the Ohio Companies increased to 62% in 2010 from 17% in 2009. The decrease in volumes was partially offset by increases in generation revenues due to higher rates from the May 2009 Ohio CBP that include the recovery of transmission costs.
The increase in wholesale generation revenues reflected higher prices and increased capacity sales for Met-Ed and Penelec in the PJM market.
Transmission revenues decreased $195 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; transmission costs are now a component of the cost of generation established under the May 2009 Ohio CBP.
Expenses —
Total expenses decreased by $1.5 billion due to the following:
| • | Purchased power costs were $1.3 billion lower in 2010, largely due to lower volume requirements. The decrease in volumes from non-affiliates resulted principally from the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the increase in customer shopping in the Ohio Companies’ service territories. The decrease in purchases from FES also resulted from the increase in customer shopping in Ohio. |
| • | An increase in purchased power unit costs from non-affiliates in 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec. A decrease in unit costs for purchases from FES was principally due to the lower weighted average unit price per KWH established under the May 2009 CBP auction for the Ohio Companies effective June 1, 2009. |
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| Increase | ||||
| Source of Change in Purchased Power | (Decrease) | |||
| (In millions) | ||||
| Purchases from non-affiliates: | ||||
| Change due to increased unit costs | $ | 619 | ||
| Change due to decreased volumes | (1,489 | ) | ||
| (870 | ) | |||
| Purchases from FES: | ||||
| Change due to decreased unit costs | (257 | ) | ||
| Change due to decreased volumes | (250 | ) | ||
| (507 | ) | |||
| Decrease in costs deferred | 83 | |||
| Net Decrease in Purchased Power Costs | $ | (1,294 | ) | |
| • | Transmission expenses increased $70 million primarily due to higher PJM network transmission expenses and congestion costs for Met-Ed and Penelec, partially offset by lower MISO network transmission expenses that are reflected in the generation rate established under the May 2009 Ohio CBP. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings. |
| • | Energy efficiency program costs, which are also recovered through rates, increased $41 million in 2010 compared to 2009. |
| • | Labor and employee benefit expenses decreased by $34 million due to lower pension and OPEB expenses, lower payroll costs resulting from staffing reductions implemented in 2009, and restructuring expenses recognized in 2009. |
| • | Expenses for economic development commitments related to the Ohio Companies’ ESP were lower by $11 million in 2010 compared to 2009. |
| • | Depreciation expense increased $6 million due to property additions since 2009. |
| • | Amortization of regulatory assets decreased $433 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in 2009, reduced net MISO and PJM transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by increased amortization associated with the accelerated recovery of deferred distribution costs in Ohio and a $35 million regulatory asset impairment in 2010 associated with the Ohio Companies’ ESP. |
| • | The deferral of new regulatory assets decreased $136 million in 2010 due to CEI’s purchased power cost deferrals that ended in early 2009. |
| • | General taxes increased $12 million principally due to a benefit relating to Ohio KWH excise taxes that was recognized in 2009 and applicable to prior years. |
Other Expense —
Other expense increased $59 million in 2010 compared to 2009 primarily due to lower nuclear decommissioning trust investment income ($37 million) and higher net interest expense associated with debt issuances by the Utilities during 2009 ($22 million).
Competitive Energy Services — 2010 Compared to 2009
Net income decreased to $258 million in 2010 compared to $517 million in 2009. The decrease in net income was primarily due to $384 million of impairment charges ($240 million net of tax) in 2010. In addition, FES sold a 6.65% participation interest in OVEC in 2010 compared to a 9% interest in 2009, accounting for $105 million of the reduction in net income. Investment income from nuclear decommissioning trusts was also lower in 2010. These reductions were partially offset by an increase in sales margins.
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Revenues —
Total revenues increased $1,108 million in 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies, other wholesale sales and the reduced OVEC participation interest sale in 2010.
The increase in reported segment revenues resulted from the following sources:
| Increase | ||||||||||||
| Revenues by Type of Service | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Direct and Government Aggregation | $ | 2,494 | $ | 779 | $ | 1,715 | ||||||
| POLR | 2,436 | 2,863 | (427 | ) | ||||||||
| Wholesale | 550 | 632 | (82 | ) | ||||||||
| Transmission | 77 | 73 | 4 | |||||||||
| RECs | 74 | 17 | 57 | |||||||||
| Sale of OVEC participation interest | 85 | 252 | (167 | ) | ||||||||
| Other | 129 | 121 | 8 | |||||||||
| Total Revenues | $ | 5,845 | $ | 4,737 | $ | 1,108 | ||||||
The increase in direct and government aggregation revenues of $1.7 billion resulted from increased revenue from the acquisition of new commercial and industrial customers as well as from new government aggregation contracts with communities in Ohio that provide generation to 1.5 million residential and small commercial customers at the end of 2010 compared to approximately 600,000 customers at the end of 2009. Increases in direct sales were partially offset by lower unit prices. Sales to residential and small commercial customers were also bolstered by summer weather in the delivery area that was significantly warmer than in 2009.
The decrease in POLR revenues of $427 million was due to lower sales volumes and lower unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $82 million due to reduced volumes, partially offset by higher prices. Lower sales volumes in MISO were due to available capacity serving increased retail sales in Ohio partially offset by increased sales under bilateral agreements in PJM.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| Increase | ||||
| Source of Change in Direct and Government Aggregation | (Decrease) | |||
| (In millions) | ||||
| Direct Sales: | ||||
| Effect of increase in sales volumes | $ | 1,083 | ||
| Change in prices | (82 | ) | ||
| 1,001 | ||||
| Government Aggregation: | ||||
| Effect of increase in sales volumes | 704 | |||
| Change in prices | 10 | |||
| 714 | ||||
| Net Increase in Direct and Government Aggregation Revenues | $ | 1,715 | ||
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| Increase | ||||
| Source of Change in Wholesale Revenues | Decrease | |||
| (In millions) | ||||
| POLR: | ||||
| Effect of 5.3% decrease in sales volumes | $ | (153 | ) | |
| Change in prices | (274 | ) | ||
| (427 | ) | |||
| Other Wholesale: | ||||
| Effect of 26.5% decrease in sales volumes | (105 | ) | ||
| Change in prices | 23 | |||
| (82 | ) | |||
| Net Decrease in Wholesale Revenues | $ | (509 | ) | |
Expenses —
Total expenses increased $1.5 billion in 2010 due to the following factors:
| • | Fuel costs increased $287 million in 2010 compared to 2009 primarily due to increased volumes consumed ($217 million) and higher unit prices ($70 million). The higher volumes consumed in 2010 were due to increased sales to direct and government aggregation customers, improved economic conditions and improved generating unit availability. The increase in unit prices was due primarily to increased coal transportation costs and to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and 2010. |
| • | Purchased power costs increased $728 million. Increased volumes purchased primarily relate to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec. |
| • | Fossil operating costs decreased $12 million due primarily to lower labor and professional and contractor costs, which were partially offset by reduced gains from the sale of emission allowances and excess coal. |
| • | Nuclear operating costs decreased $21 million due primarily to lower labor, consulting and contractor costs partially offset by increased nuclear property insurance and employee benefit costs. The year 2010 had one less refueling outage and fewer extended outages than the same period of 2009. |
| • | Transmission expenses increased $25 million due primarily to increased costs in MISO of $170 million from higher network, ancillary and congestion costs, partially offset by lower PJM transmission expenses of $145 million due to lower congestion costs. |
| • | Depreciation expense decreased $16 million principally due to reduced depreciable property associated with the impairments described below and the sale of the Sumpter plant in early 2010. |
| • | General taxes increased $5 million due to an increase in revenue-related taxes. |
| • | Other expenses increased $465 million primarily due to a $384 million impairment charge ($240 million net of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity and uncertainty related to proposed new federal environmental regulations. Expenses were also increased due to the significant growth in FES’ retail business — professional and contractor expenses, billings from affiliated service companies, uncollectible customer accounts and agent fees. |
Other Expense —
Total other expense in 2010 was $93 million higher than the same period in 2009, primarily due to a decrease in nuclear decommissioning trust investment income ($66) million and a $23 million increase in net interest expense from new long-term debt issued in late 2009 combined with the restructuring of outstanding PCRBs that occurred throughout 2009 and 2010.
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Other — 2010 Compared to 2009
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $135 million decrease in earnings available to FirstEnergy in 2010 compared to 2009. The decrease resulted primarily from increased income tax expense ($342 million) due in part to the absence of favorable tax settlements that occurred in 2009 ($200 million), partially offset by the absence of 2009 debt retirement costs in connection with the tender offer for holding company debt ($90 million), decreased interest expense associated with the debt retirement ($53 million), increased investment income ($20 million) and decreased depreciation ($20 million).
Summary of Results of Operations — 2009 Compared with 2008
Financial results for FirstEnergy’s major business segments in 2009 were as follows:
| Energy | Competitive | Other and | ||||||||||||||
| Delivery | Energy | Reconciling | FirstEnergy | |||||||||||||
| 2009 Financial Results | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | 10,585 | $ | 1,447 | $ | — | $ | 12,032 | ||||||||
| Other | 559 | 447 | (82 | ) | 924 | |||||||||||
| Internal* | — | 2,843 | (2,826 | ) | 17 | |||||||||||
| Total Revenues | 11,144 | 4,737 | (2,908 | ) | 12,973 | |||||||||||
| Expenses: | ||||||||||||||||
| Fuel | — | 1,153 | — | 1,153 | ||||||||||||
| Purchased power | 6,560 | 996 | (2,826 | ) | 4,730 | |||||||||||
| Other operating expenses | 1,424 | 1,357 | (84 | ) | 2,697 | |||||||||||
| Provision for depreciation | 445 | 270 | 21 | 736 | ||||||||||||
| Amortization of regulatory assets | 1,155 | — | — | 1,155 | ||||||||||||
| Deferral of new regulatory assets | (136 | ) | — | — | (136 | ) | ||||||||||
| Impairment of long lived assets | — | 6 | — | 6 | ||||||||||||
| General taxes | 641 | 108 | 4 | 753 | ||||||||||||
| Total Expenses | 10,089 | 3,890 | (2,885 | ) | 11,094 | |||||||||||
| Operating Income | 1,055 | 847 | (23 | ) | 1,879 | |||||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | 139 | 121 | (56 | ) | 204 | |||||||||||
| Interest expense | (472 | ) | (166 | ) | (340 | ) | (978 | ) | ||||||||
| Capitalized interest | 3 | 60 | 67 | 130 | ||||||||||||
| Total Other Expense | (330 | ) | 15 | (329 | ) | (644 | ) | |||||||||
| Income Before Income Taxes | 725 | 862 | (352 | ) | 1,235 | |||||||||||
| Income taxes | 290 | 345 | (390 | ) | 245 | |||||||||||
| Net Income | 435 | 517 | 38 | 990 | ||||||||||||
| Loss attributable to noncontrolling interest | — | — | (16 | ) | (16 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | 435 | $ | 517 | $ | 54 | $ | 1,006 | ||||||||
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. |
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| Energy | Competitive | Other and | ||||||||||||||
| Delivery | Energy | Reconciling | FirstEnergy | |||||||||||||
| 2008 Financial Results | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | 11,360 | $ | 1,333 | $ | — | $ | 12,693 | ||||||||
| Other | 708 | 238 | (12 | ) | 934 | |||||||||||
| Internal | — | 2,968 | (2,968 | ) | — | |||||||||||
| Total Revenues | 12,068 | 4,539 | (2,980 | ) | 13,627 | |||||||||||
| Expenses: | ||||||||||||||||
| Fuel | 2 | 1,338 | — | 1,340 | ||||||||||||
| Purchased power | 6,480 | 779 | (2,968 | ) | 4,291 | |||||||||||
| Other operating expenses | 2,022 | 1,142 | (119 | ) | 3,045 | |||||||||||
| Provision for depreciation | 417 | 243 | 17 | 677 | ||||||||||||
| Amortization of regulatory assets | 1,053 | — | — | 1,053 | ||||||||||||
| Deferral of new regulatory assets | (316 | ) | — | — | (316 | ) | ||||||||||
| Impairment of long lived assets | — | — | — | — | ||||||||||||
| General taxes | 646 | 109 | 23 | 778 | ||||||||||||
| Total Expenses | 10,304 | 3,611 | (3,047 | ) | 10,868 | |||||||||||
| Operating Income | 1,764 | 928 | 67 | 2,759 | ||||||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | 171 | (34 | ) | (78 | ) | 59 | ||||||||||
| Interest expense | (411 | ) | (152 | ) | (191 | ) | (754 | ) | ||||||||
| Capitalized interest | 3 | 44 | 5 | 52 | ||||||||||||
| Total Other Expense | (237 | ) | (142 | ) | (264 | ) | (643 | ) | ||||||||
| Income Before Income Taxes | 1,527 | 786 | (197 | ) | 2,116 | |||||||||||
| Income taxes | 611 | 314 | (148 | ) | 777 | |||||||||||
| Net Income | 916 | 472 | (49 | ) | 1,339 | |||||||||||
| Loss attributable to noncontrolling interest | — | — | (3 | ) | (3 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | 916 | $ | 472 | $ | (46 | ) | $ | 1,342 | |||||||
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| Energy | Competitive | Other and | ||||||||||||||
| Changes Between 2009 and 2008 Financial | Delivery | Energy | Reconciling | FirstEnergy | ||||||||||||
| Results Increase (Decrease) | Services | Services | Adjustments | Consolidated | ||||||||||||
| (In millions) | ||||||||||||||||
| Revenues: | ||||||||||||||||
| External | ||||||||||||||||
| Electric | $ | (775 | ) | $ | 114 | $ | — | $ | (661 | ) | ||||||
| Other | (149 | ) | 209 | (70 | ) | (10 | ) | |||||||||
| Internal* | — | (125 | ) | 142 | 17 | |||||||||||
| Total Revenues | (924 | ) | 198 | 72 | (654 | ) | ||||||||||
| Expenses: | ||||||||||||||||
| Fuel | (2 | ) | (185 | ) | — | (187 | ) | |||||||||
| Purchased power | 80 | 217 | 142 | 439 | ||||||||||||
| Other operating expenses | (598 | ) | 215 | 35 | (348 | ) | ||||||||||
| Provision for depreciation | 28 | 27 | 4 | 59 | ||||||||||||
| Amortization of regulatory assets | 102 | — | — | 102 | ||||||||||||
| Deferral of new regulatory assets | 180 | — | — | 180 | ||||||||||||
| Impairment of long lived assets | — | 6 | — | 6 | ||||||||||||
| General taxes | (5 | ) | (1 | ) | (19 | ) | (25 | ) | ||||||||
| Total Expenses | (215 | ) | 279 | 162 | 226 | |||||||||||
| Operating Income | (709 | ) | (81 | ) | (90 | ) | (880 | ) | ||||||||
| Other Income (Expense): | ||||||||||||||||
| Investment income | (32 | ) | 155 | 22 | 145 | |||||||||||
| Interest expense | (61 | ) | (14 | ) | (149 | ) | (224 | ) | ||||||||
| Capitalized interest | — | 16 | 62 | 78 | ||||||||||||
| Total Other Expense | (93 | ) | 157 | (65 | ) | (1 | ) | |||||||||
| Income Before Income Taxes | (802 | ) | 76 | (155 | ) | (881 | ) | |||||||||
| Income taxes | (321 | ) | 31 | (242 | ) | (532 | ) | |||||||||
| Net Income | (481 | ) | 45 | 87 | (349 | ) | ||||||||||
| Loss attributable to noncontrolling interest | — | — | (13 | ) | (13 | ) | ||||||||||
| Earnings available to FirstEnergy Corp. | $ | (481 | ) | $ | 45 | $ | 100 | $ | (336 | ) | ||||||
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sale of RECs by FES to the Ohio Companies that are retained in inventory. |
Energy Delivery Services — 2009 Compared to 2008
Net income decreased $481 million to $435 million in 2009 compared to $916 million in 2008, primarily due to lower revenues, increased purchased power costs and decreased deferrals of new regulatory assets, partially offset by lower other operating expenses.
Revenues —
The decrease in total revenues resulted from the following sources:
| Increase | ||||||||||||
| Revenues by Type of Service | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Distribution services | $ | 3,420 | $ | 3,882 | $ | (462 | ) | |||||
| Generation sales: | ||||||||||||
| Retail | 5,760 | 5,768 | (8 | ) | ||||||||
| Wholesale | 752 | 962 | (210 | ) | ||||||||
| Total generation sales | 6,512 | 6,730 | (218 | ) | ||||||||
| Transmission | 1,023 | 1,268 | (245 | ) | ||||||||
| Other | 189 | 188 | 1 | |||||||||
| Total Revenues | $ | 11,144 | $ | 12,068 | $ | (924 | ) | |||||
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The decrease in distribution deliveries by customer class is summarized in the following table:
| Electric Distribution KWH Deliveries | ||||
| Residential | (3.3 | )% | ||
| Commercial | (4.4 | )% | ||
| Industrial | (14.7 | )% | ||
| Total Distribution KWH Deliveries | (7.3 | )% | ||
The lower revenues from distribution services were driven primarily by the reductions in sales volume associated with milder weather and economic conditions. The decrease in residential deliveries reflected reduced weather-related usage compared to 2008, as cooling degree days and heating degree days decreased by 17% and 1%, respectively. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy’s service territory. In the industrial sector, KWH deliveries declined to major automotive customers by 20.2% and to steel customers by 36.2%. Reduced revenues from transition charges for OE and TE that ceased with the full recovery of related costs effective January 1, 2009 and the transition rate reduction for CEI effective June 1, 2009, were offset by PUCO-approved distribution rate increases (see Regulatory Matters — Ohio).
The following table summarizes the price and volume factors contributing to the $218 million decrease in generation revenues in 2009 compared to 2008:
| Increase | ||||
| Source of Change in Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Retail: | ||||
| Effect of 10.5% decrease in sales volumes | $ | (603 | ) | |
| Change in prices | 595 | |||
| (8 | ) | |||
| Wholesale: | ||||
| Effect of 14.9% decrease in sales volumes | (143 | ) | ||
| Change in prices | (67 | ) | ||
| (210 | ) | |||
| Net Decrease in Generation Revenues | $ | (218 | ) | |
The decrease in retail generation sales volumes from 2008 was primarily due to the weakened economic conditions and milder weather described above. Retail generation prices increased for JCP&L and Penn during 2009 as a result of their power procurement processes. For the Ohio Companies, average prices increased primarily due to the higher fuel cost recovery riders that were effective from January through May 2009. In addition, effective June 1, 2009, the Ohio Companies’ transmission tariff ended and transmission costs became a component of the generation rate established under the CBP.
Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.
Transmission revenues decreased $245 million primarily due to the termination of the Ohio Companies’ current transmission tariff and lower MISO and PJM transmission revenues, partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders (see Regulatory Matters). The difference between transmission revenues accrued and transmission costs incurred are deferred, resulting in no material effect on current period earnings.
Expenses —
Total expenses increased by $215 million due to the following:
| • | Purchased power costs were $80 million higher in 2009 due to higher unit costs, partially offset by an increase in volumes combined with higher NUG cost deferrals. The increased purchased power costs from non-affiliates was due primarily to increased volumes for the Ohio Companies as a result of their CBP, partially offset by lower volumes for Met-Ed and Penelec due to the termination of a third-party supply contract in December 2008 and for JCP&L due to the termination of a NUG purchase contract in October 2008. Decreased purchased power costs from FES were principally due to lower volumes for the Ohio Companies following their CBP, partially offset by increased volumes for Met-Ed and Penelec under their fixed-price partial requirements PSA with FES. Higher unit costs from FES, which included a component for transmission under the Ohio Companies’ CBP, partially offset the decreased volumes. |
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The following table summarizes the sources of changes in purchased power costs:
| Increase | ||||
| Source of Change in Purchased Power | (Decrease) | |||
| (In millions) | ||||
| Purchases from non-affiliates: | ||||
| Change due to increased unit costs | $ | 58 | ||
| Change due to increased volumes | 312 | |||
| 370 | ||||
| Purchases from FES: | ||||
| Change due to increased unit costs | 583 | |||
| Change due to decreased volumes | (725 | ) | ||
| (142 | ) | |||
| Increase in NUG costs deferred | (148 | ) | ||
| Net Increase in Purchased Power Costs | $ | 80 | ||
| • | Transmission expenses were lower by $481 million in 2009, reflecting the change in the transmission tariff under the Ohio Companies’ CBP, reduced transmission volumes and lower congestion costs. |
| • | Intersegment cost reimbursements related to the Ohio Companies’ nuclear generation leasehold interests increased by $114 million in 2009. Prior to 2009, a portion of OE’s and TE’s leasehold costs were recovered through customer transition charges. Effective January 1, 2009, these leasehold costs are reimbursed from the competitive energy services segment. |
| • | Labor and employee benefit expenses decreased by $39 million reflecting changes to Energy Delivery’s organizational and compensation structure and increased resources dedicated to capital projects, partially offset by higher pension expenses resulting from reduced pension plan asset values at the end of 2008. |
| • | Storm-related costs were $16 million lower in 2009 compared to the prior year. |
| • | An increase in other operating expenses of $40 million resulted from the recognition of economic development and energy efficiency obligations in accordance with the PUCO-approved ESP. |
| • | Uncollectible expenses were higher by $12 million in 2009 principally due to increased bankruptcies. |
| • | A $102 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets ($216 million) and MISO/PJM transmission cost amortization in 2009, partially offset by the cessation of transition cost amortization for OE and TE. |
| • | A $180 million decrease in the deferral of new regulatory assets was principally due to the absence in 2009 of PJM transmission cost deferrals and RCP distribution cost deferrals, partially offset by the PUCO-approved deferral of purchased power costs for CEI. |
| • | Depreciation expense increased $28 million due to property additions since 2008. |
| • | General taxes decreased $5 million due primarily to lower revenue-related taxes in 2009. |
Other Expense —
Other expense increased $93 million in 2009 compared to 2008. Lower investment income of $32 million resulted primarily from repaid notes receivable from affiliates. Higher interest expense (net of capitalized interest) of $61 million resulted from a net increase in debt of $1.8 billion by the Utilities and ATSI during 2009.
Competitive Energy Services — 2009 Compared to 2008
Net income increased to $517 million in 2009 compared to $472 million in the same period of 2008. The increase in net income includes FGCO’s gain from the sale of a 9% participation interest in OVEC, increased sales margins, and an increase in investment income, offset by a mark-to-market adjustment relating to purchased power contracts for delivery in 2010 and 2011.
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Revenues —
Total revenues increased $198 million in 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.
The increase in reported segment revenues resulted from the following sources:
| Increase | ||||||||||||
| Revenues by Type of Service | 2009 | 2008 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Non-Affiliated Generation Sales: | ||||||||||||
| Retail | $ | 778 | $ | 615 | $ | 163 | ||||||
| Wholesale | 669 | 718 | (49 | ) | ||||||||
| Total Non-Affiliated Generation Sales | 1,447 | 1,333 | 114 | |||||||||
| Affiliated Generation Sales | 2,843 | 2,968 | (125 | ) | ||||||||
| Transmission | 73 | 150 | (77 | ) | ||||||||
| Sale of OVEC participation interest | 252 | — | 252 | |||||||||
| Other | 122 | 88 | 34 | |||||||||
| Total Revenues | $ | 4,737 | $ | 4,539 | $ | 198 | ||||||
The increase in non-affiliated retail revenues of $163 million resulted from increased revenue in both the PJM and MISO markets. The increase in MISO retail revenue is primarily the result of the acquisition of new customers, higher unit prices and the inclusion of the transmission related component in retail rates previously reported as transmission revenues. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. The acquisition of new customers in MISO is primarily due to new government aggregation contracts with 60 area communities in Ohio that will provide discounted generation prices to approximately 580,000 residential and small commercial customers. Lower non-affiliated wholesale revenues of $49 million resulted from decreased sales volumes in PJM partially offset by increased capacity prices, increased sales volumes in MISO, and favorable settlements on hedged transactions.
The lower affiliated company wholesale generation revenues of $125 million were due to lower sales volumes to the Ohio Companies combined with lower unit prices to the Pennsylvania companies, partially offset by higher unit prices to the Ohio Companies and increased sales volumes to the Pennsylvania Companies. The lower sales volumes and higher unit prices to the Ohio Companies reflected the results of the power procurement processes in the first half of 2009 (see Regulatory Matters — Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES partially offset by lower sales to Penn due to decreased default service requirements in 2009 compared to 2008. Additionally, while unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall price to decline.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| Increase | ||||
| Source of Change in Non-Affiliated Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Retail: | ||||
| Effect of 8.6% increase in sales volumes | $ | 53 | ||
| Change in prices | 110 | |||
| 163 | ||||
| Wholesale: | ||||
| Effect of 13.9% decrease in sales volumes | (100 | ) | ||
| Change in prices | 51 | |||
| (49 | ) | |||
| Net Increase in Non-Affiliated Generation Revenues | $ | 114 | ||
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| Increase | ||||
| Source of Change in Affiliated Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Retail: | ||||
| Effect of 36.3% decrease in sales volumes | $ | (837 | ) | |
| Change in prices | 645 | |||
| (192 | ) | |||
| Wholesale: | ||||
| Effect of 14.7% increase in sales volumes | 97 | |||
| Change in prices | (30 | ) | ||
| 67 | ||||
| Net Decrease in Affiliated Generation Revenues | $ | (125 | ) | |
Transmission revenues decreased $77 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008 and to the inclusion of the transmission-related component in the retail rates in mid-2009. In 2009 FGCO sold 9% of its participation interest in OVEC resulting in a $252 million ($158 million, after tax) gain. Other revenue increased $28 million primarily due to income associated with NGC’s acquisition of equity interests in the Perry and Beaver Valley Unit 2 leases.
Expenses —
Total expenses increased $279 million in 2009 due to the following factors:
| • | Fossil Fuel costs decreased $198 million due primarily to lower generation volumes ($307 million) partially offset by higher unit prices ($109 million). Nuclear Fuel costs increased $13 million as higher unit prices ($26 million) were partially offset by lower generation ($13 million). |
| • | Purchased power costs increased $217 million due to a mark-to-market adjustment ($205 million) relating to purchased power contracts for delivery in 2010 and 2011 and higher unit prices ($33 million) that resulted primarily from higher capacity costs, partially offset by lower volumes purchased ($21 million) due to FGCO’s reduced participation interest in OVEC. |
| • | Fossil operating costs decreased $24 million due primarily to a reduction in contractor, material and labor costs and increased resources dedicated to capital projects, partially offset by higher employee benefits. |
| • | Nuclear operating costs increased $45 million due to an additional refueling outage during the 2009 period and higher employee benefits, partially offset by lower labor costs. |
| • | Transmission expense increased $121 million due to transmission services charges related to the load serving entity obligations in MISO, increased net congestion and higher loss expenses in MISO and PJM. |
| • | Other expense increased $78 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension costs. |
| • | Depreciation expense increased $27 million due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry. |
Other Income (Expense) —
Total other income in 2009 was $15 million compared to total other expense in 2008 of $142 million, resulting primarily from a $155 million increase from gains on the sale of nuclear decommissioning trust investments. During 2009, the majority of the nuclear decommissioning trust holdings were converted to more closely align with the liability being funded.
Other — 2009 Compared to 2008
Our financial results from other operating segments and reconciling items resulted in a $100 million increase in net income in 2009 compared to 2008. The increase resulted primarily from $200 million of favorable tax settlements, offset by debt redemption costs of $90 million and by the absence of the gain from the sale of telecommunication assets ($19 million, net of taxes) in 2008.
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POSTRETIREMENT BENEFITS
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of our employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. We also provide health care benefits, which include certain employee contributions, deductibles, and co-payments, upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. Benefit plan assets and obligations are remeasured annually using a December 31 measurement date. Adverse market conditions during 2008 increased 2009 costs, which were partially offset by the effects of a $500 million voluntary cash pension contribution and an OPEB plan amendment in 2009. Recovering market conditions and greater returns on higher asset levels decreased postretirement benefit expense in 2010, partially offset by a full year of realization on the reduction in benefit liability resulting from the OPEB plan amendment in 2009. Pension and OPEB expenses are included in various cost categories and have contributed to cost increases discussed above for 2010. The following table reflects the portion of qualified and non-qualified pension and OPEB costs that were charged to expense in the three years ended December 31, 2010:
| Postretirement Benefits Expense (Credits) | 2010 | 2009 | 2008 | |||||||||
| (In millions) | ||||||||||||
| Pension | $ | 174 | $ | 185 | $ | (23 | ) | |||||
| OPEB | (90 | ) | (40 | ) | (37 | ) | ||||||
| Total | $ | 84 | $ | 145 | $ | (60 | ) | |||||
As of December 31, 2010, our pension plan was underfunded and we currently anticipate that an additional voluntary cash contribution of $250 million will be made in 2011.
The overall actual investment result during 2010 was a gain of 10% compared to an assumed 8.5% return. Based on discount rates of 5.50% for pension, 5.00% for OPEB and an estimated return on assets of 8.25%, our 2011 pre-tax net periodic postretirement benefit expense is expected to be approximately $92 million.
SUPPLY PLAN
Regulated Commodity Sourcing
The Utilities have a default service obligation to provide power to non-shopping customers who have elected to continue to receive service under regulated retail tariffs. The volume of these sales can vary depending on the level of shopping that occurs. Supply plans vary by state and by service territory. JCP&L’s default service supply is secured through a statewide competitive procurement process approved by the NJBPU. The Ohio Companies and Penn’s default service supplies are provided through a competitive procurement process approved by the PUCO and PPUC, respectively. The default service supply for Met-Ed and Penelec was secured through a FERC-approved agreement with FES through 2010, transitioning to a PPUC-approved competitive procurement process in 2011. If any supplier fails to deliver power to any one of the Utilities’ service areas, the Utility serving that area may need to procure the required power in the market in their role as a POLR.
Unregulated Commodity Sourcing
FES provides energy and energy related services, including the generation and sale of electricity and energy planning and procurement through retail and wholesale competitive supply arrangements. FES controls 13,236 MW of installed generating capacity. FES supplies the power requirements of its competitive load-serving obligations through a combination of subsidiary-owned generation, non-affiliated contracts and spot market transactions.
FES has retail and wholesale competitive load-serving obligations in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey serving both affiliated and non-affiliated companies. FES provides energy products and services to customers under various POLR, shopping, competitive-bid and non-affiliated contractual obligations. In 2010, FES’ generation was used to serve two primary obligations — affiliated companies utilized approximately 43% of FES’ total generation and retail customers utilized approximately 43% of FES’ total generation. Geographically, approximately 60% of FES’ obligation is located in the MISO market area and 40% is located in the PJM market area.
CAPITAL RESOURCES AND LIQUIDITY
As of December 31, 2010, FirstEnergy had cash and cash equivalents of approximately $1 billion available to fund investments, operations and capital expenditures. To fund liquidity and capital requirements for 2011 and beyond, FirstEnergy may rely on internal and external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities.
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FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2011, FirstEnergy expects to satisfy these requirements with a combination of internal cash from operations and external funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s ability to fund current liquidity and capital resource requirements. To mitigate risk, FirstEnergy’s business model stresses financial discipline and a strong focus on execution. Major elements of this business model include the expectation of: projected cash from operations, opportunities for favorable long-term earnings growth as the transition to competitive generation markets is completed, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend (dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations) and a successful merger integration.
As of December 31, 2010, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of December 31, 2010, included the following (in millions):
| Currently Payable Long-term Debt | ||||
PCRBs supported by bank LOCs (1) | $ | 827 | ||
FGCO and NGC PCRBs (1) | 191 | |||
Penelec unsecured PCRBs | 25 | |||
FirstEnergy Corp. unsecured note | 250 | |||
NGC collateralized lease obligation bonds | 50 | |||
Sinking fund requirements | 33 | |||
FES term loan | 100 | |||
Other obligations | 10 | |||
| $ | 1,486 | |||
| (1) | Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. |
Short-Term Borrowings
FirstEnergy had approximately $700 million of short-term borrowings as of December 31, 2010 and $1.1 billion as of December 31, 2009. FirstEnergy’s available liquidity as of January 31, 2011, is summarized in the following table:
| Available | ||||||||||||||||
| Company | Type | Maturity | Commitment | Liquidity | ||||||||||||
| (In millions) | ||||||||||||||||
FirstEnergy(1) | Revolving | Aug. 2012 | $ | 2,750 | $ | 2,245 | ||||||||||
| FES | Term loan | Mar. 2011 | 100 | — | ||||||||||||
| Ohio and Pennsylvania Companies | Receivables financing | Various | (2) | 395 | 237 | |||||||||||
| Subtotal | $ | 3,245 | $ | 2,482 | ||||||||||||
| Cash | — | 668 | ||||||||||||||
| Total | $ | 3,245 | $ | 3,150 | ||||||||||||
| (1) | FirstEnergy Corp. and subsidiary borrowers. | |
| (2) | Ohio — $250 million matures March 30, 2011; Pennsylvania — $145 million matures June 17, 2011 with optional extension terms. |
On October 22, 2010, Signal Peak and Global Rail, as borrowers, entered into a $350 million syndicated two-year senior secured term loan facility. The loan proceeds were used to repay $258 million of notes payable to FirstEnergy, including $9 million of interest and $63 million of bank loans that were scheduled to mature on November 16, 2010. Additional proceeds were used for general company purposes, including an $11 million repayment of a third-party seller’s note. As discussed below under Guarantees and Other Assurances, FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV in the borrowers, have provided a guaranty of the borrowers’ obligations under the facility.
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Revolving Credit Facility
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2010:
| Revolving | Regulatory and | |||||||
| Credit Facility | Other Short-Term | |||||||
| Borrower | Sub-Limit | Debt Limitations | ||||||
| (In millions) | ||||||||
| FirstEnergy | $ | 2,750 | $ | — | (1) | |||
| FES | 1,000 | — | (1) | |||||
| OE | 500 | 500 | ||||||
| Penn | 50 | 34 | (2) | |||||
| CEI | 250 | (3) | 500 | |||||
| TE | 250 | (3) | 500 | |||||
| JCP&L | 425 | 411 | (2) | |||||
| Met-Ed | 250 | 300 | (2) | |||||
| Penelec | 250 | 300 | (2) | |||||
| ATSI | 50 | (4) | 100 | |||||
| (1) | No regulatory approvals, statutory or charter limitations applicable. | |
| (2) | Excluding amounts that may be borrowed under the regulated companies’ money pool. | |
| (3) | Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. | |
| (4) | The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that ATSI has received regulatory approval to have short-term borrowings up to the same amount. |
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of December 31, 2010, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
| Borrower | ||||
FirstEnergy | 60.6 | % | ||
FES | 52.6 | % | ||
OE | 54.1 | % | ||
Penn | 37.7 | % | ||
CEI | 57.1 | % | ||
TE | 57.6 | % | ||
JCP&L | 34.6 | % | ||
Met-Ed | 41.5 | % | ||
Penelec | 54.7 | % | ||
ATSI | 48.3 | % |
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As of December 31, 2010, FirstEnergy could issue additional debt of approximately $3.2 billion, or recognize a reduction in equity of approximately $1.7 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy Money Pools
FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2010 was 0.51% per annum for the regulated companies’ money pool and 0.60% per annum for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of December 31, 2010, FirstEnergy’s currently payable long-term debt included approximately $827 million (FES — $778 million, Met-Ed — $29 million and Penelec — $20 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of December 31, 2010:
| Aggregate LOC | Reimbursements of | |||||||
| LOC Bank | Amount(2) | LOC Termination Date | LOC Draws Due | |||||
| (In millions) | ||||||||
CitiBank N.A. | $ | 166 | June 2014 | June 2014 | ||||
The Bank of Nova Scotia | 178 | Beginning April 2011 | Multiple dates(3) | |||||
The Royal Bank of Scotland | 131 | June 2012 | 6 months | |||||
Wachovia Bank | 152 | March 2014 | March 2014 | |||||
Barclays Bank(1) | 208 | April 2011 | 30 days | |||||
Total | $ | 835 | ||||||
| (1) | Supported by 13 participating banks, with no one bank having more than 22% of the total commitment. | |
| (2) | Includes approximately $8 million of applicable interest coverage. | |
| (3) | Shorter of 6 months or LOC termination date ($49 million) and shorter of one year or LOC termination date ($129 million). |
On August 20, 2010, FES completed the remarketing of $250 million of PCRBs. Of the $250 million, $235 million of PCRBs were converted from a variable interest rate to a fixed interest rate. The remaining $15 million of PCRBs continue to bear a fixed interest rate. The interest rate conversion minimizes financial risk by converting the long-term debt into a fixed rate and, as a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million of PCRBs that now bears a per-annum rate of 2.25% and is subject to mandatory purchase on June 3, 2013; and $15 million of PCRBs that now bears a per-annum rate of 1.5% and is subject to mandatory purchase on June 1, 2011.
On October 1, 2010, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These PCRBs were converted from a variable interest rate to a fixed long term interest rate of 3.375% per annum and are subject to mandatory purchase on July 1, 2015.
On December 3, 2010, FES completed the remarketing of four series of PCRBs totaling $153 million and Penelec completed the remarketing of $25 million PCRBs. These PCRBs were converted from a variable interest rate to fixed interest rates ranging from 2.25% to 3.75% per annum.
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Long-Term Debt Capacity
As of December 31, 2010, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.4 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. The issuance of FMBs by the Ohio Companies is also subject to provisions of their senior note indentures generally limiting the incurrence of additional secured debt, subject to certain exceptions that would permit, among other things, the issuance of secured debt (including FMBs) supporting pollution control notes or similar obligations, or as an extension, renewal or replacement of previously outstanding secured debt. In addition, these provisions would permit OE and CEI to incur additional secured debt not otherwise permitted by a specified exception of up to $124 million and $26 million, respectively, as of December 31, 2010. As a result of the indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $394 million and $343 million, respectively, under provisions of their senior note indentures as of December 31, 2010.
Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of December 31, 2010, FGCO had the capability to issue $1.7 billion of additional FMBs under the terms of that indenture. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $695 million of additional FMBs as of December 31, 2010.
FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On February 11, 2010, S&P issued a report lowering FirstEnergy’s and its subsidiaries’ credit ratings by one notch, while maintaining its stable outlook. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010. On September 28, 2010, S&P issued a report reaffirming the ratings and stable outlook of FirstEnergy and its subsidiaries. Fitch revised its outlook on FirstEnergy and FES from stable to negative on December 15, 2010. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of December 31, 2010:
| Senior Secured | Senior Unsecured | |||||||||||||||||||||||
| Issuer | S&P | Moody’s | Fitch | S&P | Moody’s | Fitch | ||||||||||||||||||
| FirstEnergy Corp. | — | — | — | BB+ | Baa3 | BBB | ||||||||||||||||||
| FES | — | — | — | BBB- | Baa2 | BBB | ||||||||||||||||||
| OE | BBB | A3 | BBB+ | BBB- | Baa2 | BBB | ||||||||||||||||||
| Penn | BBB+ | A3 | BBB+ | — | — | — | ||||||||||||||||||
| CEI | BBB | Baa1 | BBB | BBB- | Baa3 | BBB- | ||||||||||||||||||
| TE | BBB | Baa1 | BBB | — | — | — | ||||||||||||||||||
| JCP&L | — | — | — | BBB- | Baa2 | BBB+ | ||||||||||||||||||
| Met-Ed | BBB | A3 | BBB+ | BBB- | Baa2 | BBB | ||||||||||||||||||
| Penelec | BBB | A3 | BBB+ | BBB- | Baa2 | BBB | ||||||||||||||||||
| ATSI | — | — | — | BBB- | Baa1 | — | ||||||||||||||||||
Changes in Cash Position
As of December 31, 2010, FirstEnergy had $1 billion of cash and cash equivalents compared to $874 million as of December 31, 2009. As of December 31, 2010 and 2009, FirstEnergy had approximately $13 million and $12 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During 2010, FirstEnergy received $850 million of cash dividends from its subsidiaries and paid $670 million in cash dividends to common shareholders.
Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities was $3.1 billion in 2010, $2.5 billion in 2009 and $2.2 billion in 2008, as summarized in the following table:
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| Operating Cash Flows | 2010 | 2009 | 2008 | |||||||||
| (In millions) | ||||||||||||
| Net income | $ | 760 | $ | 990 | $ | 1,339 | ||||||
| Non-cash charges and other adjustments | 2,309 | 2,281 | 1,405 | |||||||||
| Pension trust contribution | — | (500 | ) | — | ||||||||
| Working capital and other | 7 | (306 | ) | (520 | ) | |||||||
| $ | 3,076 | $ | 2,465 | $ | 2,224 | |||||||
The increase in non-cash charges and other adjustments is primarily due to increased impairment charges on long lived assets ($378 million) combined with higher deferred income taxes and investment tax credits ($86 million), partially offset by lower net amortization of regulatory assets of ($297 million), including the impact of CEI’s $216 million regulatory asset impairment recorded during the first quarter of 2009, and reduced charges relating to debt redemptions, primarily caused by a $142 million charge relating to debt redemptions during the third quarter of 2009.
The change in working capital and other is primarily due to cash proceeds of $129 million received on the termination of fixed-for-floating interest rate swaps during the second and third quarters of 2010, changes in investment securities of $121 million, increased accrued taxes and decreased prepayments primarily related to prepaid taxes ($279 million) and changes in uncertain tax positions ($176 million), partially offset by increased accounts receivable ($252 million), decreased accrued interest ($60 million) and increased cash collateral paid to third parties ($56 million).
Cash Flows From Financing Activities
In 2010, cash used for financing activities was $983 million compared to cash provided from financing activities of $49 million in 2009. The change was primarily due to reduced long-term debt issued in 2010 compared to 2009, partially offset by reduced long-term debt redemptions and reduced payments on short-term borrowings in 2010 as compared to 2009. The following table summarizes security issuances (net of any discounts) and redemptions:
| Securities Issued or Redeemed | 2010 | 2009 | 2008 | |||||||||
| (In millions) | ||||||||||||
New Issues | ||||||||||||
| First mortgage bonds | $ | — | $ | 398 | $ | 592 | ||||||
| Pollution control notes | 740 | 940 | 692 | |||||||||
| Senior secured notes | 350 | 297 | — | |||||||||
| Unsecured Notes | 9 | 2,997 | 83 | |||||||||
| $ | 1,099 | $ | 4,632 | $ | 1,367 | |||||||
Redemptions | ||||||||||||
| First mortgage bonds | $ | 32 | $ | 1 | $ | 126 | ||||||
| Pollution control notes | 741 | 884 | 698 | |||||||||
| Senior secured notes | 141 | 217 | 35 | |||||||||
| Unsecured notes | 101 | 1,508 | 175 | |||||||||
| $ | 1,015 | $ | 2,610 | $ | 1,034 | |||||||
| Short-term borrowings, net | $ | (378 | ) | $ | (1,246 | ) | $ | 1,494 | ||||
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for 2010, 2009 and 2008 by business segment:
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| Summary of Cash Flows | Property | |||||||||||||||
| Provided from (Used for) Investing Activities | Additions | Investments | Other | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Sources (Uses) | ||||||||||||||||
2010 | ||||||||||||||||
| Energy delivery services | $ | (745 | ) | $ | 96 | $ | 13 | $ | (636 | ) | ||||||
| Competitive energy services | (1,129 | ) | (43 | ) | (51 | ) | (1,223 | ) | ||||||||
| Other | (24 | ) | (7 | ) | 30 | (1 | ) | |||||||||
| Inter-Segment reconciling items | (65 | ) | (23 | ) | — | (88 | ) | |||||||||
| Total | $ | (1,963 | ) | $ | 23 | $ | (8 | ) | $ | (1,948 | ) | |||||
2009 | ||||||||||||||||
| Energy delivery services | $ | (750 | ) | $ | 39 | $ | (46 | ) | $ | (757 | ) | |||||
| Competitive energy services | (1,262 | ) | (8 | ) | (19 | ) | (1,289 | ) | ||||||||
| Other | (149 | ) | (3 | ) | 72 | (80 | ) | |||||||||
| Inter-Segment reconciling items | (42 | ) | (24 | ) | 7 | (59 | ) | |||||||||
| Total | $ | (2,203 | ) | $ | 4 | $ | 14 | $ | (2,185 | ) | ||||||
2008 | ||||||||||||||||
| Energy delivery services | $ | (839 | ) | $ | (41 | ) | $ | (17 | ) | $ | (897 | ) | ||||
| Competitive energy services | (1,835 | ) | (14 | ) | (56 | ) | (1,905 | ) | ||||||||
| Other | (176 | ) | 106 | (61 | ) | (131 | ) | |||||||||
| Inter-Segment reconciling items | (38 | ) | (12 | ) | — | (50 | ) | |||||||||
| Total | $ | (2,888 | ) | $ | 39 | $ | (134 | ) | $ | (2,983 | ) | |||||
Net cash used for investing activities in 2010 decreased by $237 million compared to 2009. The decrease was principally due to a $240 million decrease in property additions (principally lower AQC system expenditures) and an increase in cash proceeds from the sale of assets of $96 million, partially offset by $113 million spent by FES in the customer acquisition process.
During 2011 through 2013 we anticipate average annual baseline capital expenditures of approximately $1.2 billion, exclusive of any additional opportunities or future mandated spending. This includes approximately $133 million, $300 million and $183 million in nuclear fuel expenditures for 2011, 2012 and 2013, respectively.
CONTRACTUAL OBLIGATIONS
As of December 31, 2010, our estimated cash payments under existing contractual obligations that we consider firm obligations are as follows:
| 2012- | 2014- | |||||||||||||||||||
| Contractual Obligations | Total | 2011 | 2013 | 2015 | Thereafter | |||||||||||||||
| (In millions) | ||||||||||||||||||||
Long-term debt | $ | 13,928 | $ | 437 | $ | 995 | $ | 1,165 | $ | 11,331 | ||||||||||
Short-term borrowings | 700 | 700 | — | — | — | |||||||||||||||
Interest on long-term debt(1) | 10,978 | 793 | 1,518 | 1,379 | 7,288 | |||||||||||||||
Operating leases(2) | 3,314 | 213 | 477 | 506 | 2,118 | |||||||||||||||
Fuel and purchased power(3) | 16,851 | 2,660 | 4,015 | 3,923 | 6,253 | |||||||||||||||
Capital expenditures | 1,109 | 340 | 463 | 306 | — | |||||||||||||||
Pension funding | 1,076 | 250 | 74 | 543 | 209 | |||||||||||||||
Other(4) | 112 | 31 | 14 | 14 | 53 | |||||||||||||||
Total | $ | 48,068 | $ | 5,424 | $ | 7,556 | $ | 7,836 | $ | 27,252 | ||||||||||
| (1) | Interest on variable-rate debt based on rates as of December 31, 2010. | |
| (2) | See Note 7 to the consolidated financial statements. | |
| (3) | Amounts under contract with fixed or minimum quantities based on estimated annual requirements. | |
| (4) | Includes amounts for capital leases (see Note 7) and contingent tax liabilities (see Note 9). |
Excluded from the data shown above are estimates for the cash outlays stemming from the power purchase contracts entered into by the Utilities and under which they procure the power supply necessary to provide generation service to their customers who do not choose an alternative supplier. The exact amount of outlay will be determined by future customer behavior and consumption levels, but based on numerous planning assumptions management estimates an amount of $3.0 billion during 2011.
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GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon either FirstEnergy or its subsidiaries’ credit ratings.
As of December 31, 2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.7 billion, as summarized below:
| Maximum | ||||
| Guarantees and Other Assurances | Exposure | |||
| (In millions) | ||||
| FirstEnergy Guarantees on Behalf of its Subsidiaries | ||||
Energy and Energy-Related Contracts(1) | $ | 300 | ||
LOC (long-term debt) — Interest coverage(2) | 2 | |||
FirstEnergy guarantee of OVEC obligations | 300 | |||
Other(3) | 227 | |||
| 829 | ||||
Subsidiaries’ Guarantees | ||||
Energy and Energy-Related Contracts | 54 | |||
LOC (long-term debt) — Interest coverage(2) | 3 | |||
FES’ guarantee of NGC’s nuclear property insurance | 70 | |||
FES’ guarantee of FGCO’s sale and leaseback obligations | 2,375 | |||
Other | 2 | |||
| 2,504 | ||||
Surety Bonds | 82 | |||
LOC (long-term debt) — Interest coverage(2) | 3 | |||
LOC (non-debt)(4)(5) | 339 | |||
| 424 | ||||
Total Guarantees and Other Assurances | $ | 3,757 | ||
| (1) | Issued for open-ended terms, with a 10-day termination right by FirstEnergy. | |
| (2) | Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $827 million is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets. | |
| (3) | Includes guarantees of $15 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $39 million for railcar leases. | |
| (4) | Includes $167 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility. | |
| (5) | Includes approximately $130 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $42 million pledged in connection with the sale and leaseback of Perry by OE. |
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by FirstEnergy’s assets. FirstEnergy believes the likelihood is remote that such parental guarantees will increase amounts otherwise paid by FirstEnergy to meet its obligations incurred in connection with ongoing energy and energy-related activities.
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While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade to below investment grade, an acceleration or funding obligation or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of December 31, 2010, FirstEnergy’s maximum exposure under these collateral provisions was $468 million, as shown below:
| Collateral Provisions | FES | Utilities | Total | |||||||||
| (In millions) | ||||||||||||
Credit rating downgrade to below investment grade (1) | $ | 364 | $ | 65 | $ | 429 | ||||||
Material adverse event (2) | 39 | — | 39 | |||||||||
Total | $ | 403 | $ | 65 | $ | 468 | ||||||
| (1) | Includes $137 million and $54 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively. | |
| (2) | Includes $33 million that is also considered an acceleration of payment or funding obligation at FES. |
Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $532 million consisting of $486 million due to a below investment grade credit rating (of which $224 million is related to an acceleration of payment or funding obligation) and $46 million due to “material adverse event” contractual clauses.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $82 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of December 31, 2010, and forward prices as of that date, FES has posted collateral of $185 million. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $28 million. Depending on the volume of forward contracts and future price movements, FES could be required to post higher amounts for margining.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
As noted above under Capital Resources and Liquidity, FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC have provided a guaranty of the borrowers’ obligations under the $350 million syndicated two-year senior secured term loan facility entered into by Signal Peak and Global Rail. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the banks as collateral for the facility.
OFF-BALANCE SHEET ARRANGEMENTS
FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $1.6 billion as of December 31, 2010.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
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Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices associated with electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 6 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of December 31, 2010 are summarized by contract year in the following table:
| Source of Information- | ||||||||||||||||||||||||||||
| Fair Value by Contract Year | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Prices actively quoted(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Other external sources(2) | (331 | ) | (157 | ) | (52 | ) | (36 | ) | — | — | (576 | ) | ||||||||||||||||
Prices based on models | — | — | — | — | 24 | 110 | 134 | |||||||||||||||||||||
Total(3) | $ | (331 | ) | $ | (157 | ) | $ | (52 | ) | $ | (36 | ) | $ | 24 | $ | 110 | $ | (442 | ) | |||||||||
| (1) | Represents futures and options traded on the New York Mercantile Exchange. | |
| (2) | Primarily represents contracts based on broker and IntercontinentalExchange quotes. | |
| (3) | Includes $335 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings. |
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $16 million ($10 million net of tax) during the next 12 months.
Interest Rate Swap Agreements — Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of December 31, 2010, no fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $124 million ($80 million net of tax) as of December 31, 2010. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled $12 million during 2010.
Interest Rate Risk
FirstEnergy’s exposure to fluctuations in market interest rates is reduced since a significant portion of debt has fixed interest rates, as noted in the table below. FirstEnergy is subject to the inherent interest rate risks related to refinancing maturing debt by issuing new debt securities. As discussed in Note 7 to the consolidated financial statements, FirstEnergy’s investments in capital trusts effectively reduce future lease obligations, also reducing interest rate risk.
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Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 80 | $ | 90 | $ | 101 | $ | 110 | $ | 76 | $ | 1,755 | $ | 2,212 | $ | 2,304 | ||||||||||||||||
| Average interest rate | 8.4 | % | 8 | % | 8 | % | 8 | % | 8.1 | % | 5.7 | % | 6.2 | % | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 437 | $ | 94 | $ | 551 | $ | 536 | $ | 629 | $ | 10,504 | $ | 12,751 | $ | 13,668 | ||||||||||||||||
| Average interest rate | 5.7 | % | 7.8 | % | 5.8 | % | 5.4 | % | 5.2 | % | 6.3 | % | 6.1 | % | ||||||||||||||||||
| Variable rate | $ | 350 | $ | 827 | $ | 1,177 | $ | 1,177 | ||||||||||||||||||||||||
| Average interest rate | 2.5 | % | 0.3 | % | 1 | % | ||||||||||||||||||||||||||
| Short-term Borrowings: | $ | 700 | $ | 700 | $ | 700 | ||||||||||||||||||||||||||
| Average interest rate | 0.7 | % | 0.7 | % | ||||||||||||||||||||||||||||
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of December 31, 2010, approximately 28% of the pension plan assets are invested in equity securities, 50% invested in fixed income securities, 11% invested in absolute return strategies, 6% invested in real estate, 4% invested in private equity and 1% invested in cash. The plan is 83% funded on an accumulated benefit obligation basis as of December 31, 2010. A decline in the value of FirstEnergy’s pension plan assets could result in additional funding requirements. FirstEnergy intends to voluntarily contribute $250 million to its pension plan in 2011.
Nuclear decommissioning trust funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of December 31, 2010, approximately 73% of the funds were invested in fixed income securities, 17% of the funds were invested in equity securities and 10% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,454 million, $337 million and $189 million for fixed income securities, equity securities and short-term investments, respectively, as of December 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $34 million reduction in fair value as of December 31, 2010. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. A decline in the value of FirstEnergy’s nuclear decommissioning trusts or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $6 million was contributed to the JCP&L and Pennsylvania nuclear decommissioning trusts to comply with regulatory requirements. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.
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CREDIT RISK
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of December 31, 2010, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 10.9% of FirstEnergy’s total approved credit risk composed of 3.3% for FES, 2.2% for JCP&L, 2.7% for Met-Ed and a combined 2.7% for OE, TE and CEI.
REGULATORY MATTERS
Regulatory assets that do not earn a current return totaled approximately $215 million as of December 31, 2010 (JCP&L — $38 million, Met-Ed — $131 million, Penelec — $12 million, CEI — $16 million and OE — $18 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec.
FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred or accrued costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the recovery of costs or accrued liabilities that have been deferred because it is probable such amounts will be returned to customers through future regulated rates. The following table provides the balance of regulatory assets by Company as of December 31, 2010 and 2009, and changes during 2010:
| December 31, | December 31, | Increase | ||||||||||
| Regulatory Assets | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| OE | $ | 400 | $ | 465 | $ | (65 | ) | |||||
| CEI | 370 | 546 | (176 | ) | ||||||||
| TE | 72 | 70 | 2 | |||||||||
| JCP&L | 513 | 888 | (375 | ) | ||||||||
| Met-Ed | 296 | 357 | (61 | ) | ||||||||
| Penelec | 163 | 9 | 154 | |||||||||
| Other | 12 | 21 | (9 | ) | ||||||||
| Total | $ | 1,826 | $ | 2,356 | $ | (530 | ) | |||||
The following table provides information about the composition of regulatory assets as of December 31, 2010 and 2009 and the changes during 2010:
| December 31, | December 31, | Increase | ||||||||||
| Regulatory Assets by Source | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Regulatory transition costs | $ | 770 | $ | 1,100 | $ | (330 | ) | |||||
| Customer shopping incentives | — | 154 | (154 | ) | ||||||||
| Customer receivables for future income taxes | 326 | 329 | (3 | ) | ||||||||
| Loss on reacquired debt | 48 | 51 | (3 | ) | ||||||||
| Employee postretirement benefits | 16 | 23 | (7 | ) | ||||||||
| Nuclear decommissioning, decontamination and spent fuel disposal costs | (184 | ) | (162 | ) | (22 | ) | ||||||
| Asset removal costs | (237 | ) | (231 | ) | (6 | ) | ||||||
| MISO/PJM transmission costs | 184 | 148 | 36 | |||||||||
| Deferred generation costs | 386 | 369 | 17 | |||||||||
| Distribution costs | 426 | 482 | (56 | ) | ||||||||
| Other | 91 | 93 | (2 | ) | ||||||||
| Total | $ | 1,826 | $ | 2,356 | $ | (530 | ) | |||||
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Ohio
The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. On February 2, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing filed both by the Ohio Companies and by the other party.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The PUCO approved the new ESP on August 25, 2010 with certain modifications. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; a load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to pay certain costs related to the companies’ integration into PJM, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, established a $12 million fund to assist low income customers over the term of the ESP, and agreed to additional energy efficiency benefits. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the integration into PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. On February 9, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO, which is delaying the launch of the programs described in the plan. As a result, the Ohio Companies filed on January 11, 2011, a request for amendment of OE’s 2010 energy efficiency and peak demand reduction benchmarks to levels actually achieved in 2010. Because the Commission indicated that it would revise all of the Ohio Companies’ 2010, 2011, and 2012 benchmarks when addressing the Ohio Companies’ three year portfolio plan, and an order has yet to be issued on that plan, CEI and TE also requested a waiver of their respective yet-to-be defined 2010 energy efficiency benchmarks if and only to the degree one is deemed necessary to bring these companies into compliance with their 2010 energy efficiency obligations. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty.
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Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011. As a result of this RFP, contracts were executed in August 2010. On January 11, 2011, the Ohio Companies filed an application with the PUCO seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio due to the insufficient quantity of solar energy resources reasonably available in the market. The PUCO has not yet ruled on that application.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010, and the proceeding remains open. The hearing in the matter is set to commence on February 16, 2011.
Pennsylvania
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $252.7 million ($188.0 million for Met-Ed and $64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. The argument before the Commonwealth Court,en banc, was held on December 8, 2010.
On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. On August 12, 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan on November 6, 2009. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
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Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC on August 14, 2009. This plan proposed a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
New Jersey
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2010, the accumulated deferred cost balance was a credit of approximately $37 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. On February 10, 2011, the NJBPU approved a stipulation which allows the change in rates to become effective March 1, 2011.
On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). This matter is currently pending before the NJBPU.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.
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FERC Matters
Rates for Transmission Service Between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. On May 21, 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC on November 23, 2010, and the relevant payments made. Rehearings remain pending in this proceeding.
PJM Transmission Rate
On April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings”— meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act by May 31, 2011.
RTO Realignment
On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s withdrawal from MISO and integration into PJM. This move, which is expected to be effective on June 1, 2011, allows FirstEnergy to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The realignment will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a FRR Plan to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.
FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements. On August 25, 2010, the PUCO issued an order in the 2010 ESP Case approving a settlement that, among other things, called for the PUCO to withdraw its opposition to the RTO consolidation. In addition, the order approved a wholesale procurement process, and certain “retail choice” policies, that reflected ATSI’s entry into PJM on June 1, 2011.
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On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. Additional FERC proceedings are either pending or expected in which the amount of exit fees, transmission cost allocations, and costs associated with long term firm transmission rights payable by the ATSI zone upon its withdrawal from the Midwest ISO will be determined. In addition, certain parties may protest other aspects of ATSI’s integration into PJM, and certain of these matters remain outstanding and will be resolved in future FERC proceedings. The outcome of these proceedings cannot be predicted.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—are a class of MTEP projects. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $11 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
On September 10, 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVP projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
On December 16, 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attach prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, the Company argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time.
Sales to Affiliates
FES has received authorization from FERC to make wholesale power sales to the Utilities. FES actively participates in auctions conducted by or on behalf of the Utilities to obtain the power and related services necessary to meet the Utilities’ POLR obligations. Because of the merger with FirstEnergy, AS is considered an affiliate of the Utilities for purposes of FERC’s affiliate restriction regulations. This requires AS to obtain prior FERC authorization to make sales to the Utilities when it successfully participates in the Utilities’ POLR auctions.
FES currently supplies the Ohio Companies with a portion of their capacity, energy, ancillary services and transmission under a Master SSO Supply Agreement for a two-year period ending May 31, 2011. FES won 51 tranches in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International on May 13-14, 2009. Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009. FES also supplies power used by Constellation to serve an additional five tranches. As a result of these arrangements, FES serves 77 tranches, or 77% of the POLR load of the Ohio Companies until May 31, 2011.
On October 20, 2010, FES participated in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International, for the following periods: June 1, 2011 through May 31, 2012; June 1, 2011, through May 31, 2013; and June 1, 2010 through May 31, 2014. The Ohio Companies offered 17, 17, and 16 tranches for these periods, respectively. FES won 10, 7, and 3 tranches, respectively, for these periods. On January 25, 2011, the Ohio Companies conducted a second auction offering the same product for identical time periods. FES won 3, 0, and 3 tranches, respectively, for these periods. FES entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services, and congestion costs to the Ohio Companies for the tranches won. Under the ESP in effect for these time periods, the Ohio Companies are responsible for payment of noncontrollable transmission costs billed by PJM for POLR service.
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On October 18, 2010, FES participated in a descending clock auction for POLR service administered by both Met-Ed and Penelec and their consultant, National Economic Research Associates (NERA) for the following tranche products and delivery periods: Residential 5-month, Residential 24-month, Commercial 5-month, Commercial 12-month and Industrial 12-month. All 5-month delivery periods are from January 1, 2011 through May 31, 2011, all 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 7 Residential 5-month tranches, 4 Residential 24-month tranches, 6 Commercial 5-month tranches, 6 Commercial 12-month tranches and 1 Industrial tranche while Penelec offered 5 Residential 5-month tranches, 3 Residential 24-month tranches, 5 Commercial 5-month tranches, 5 Commercial 12-month tranches and 1 Industrial tranche.
For Met-Ed offerings, FES won 4 Residential 5-month tranches, 2 Residential 24-month tranches, 1 Commercial 5-month tranche, 1 Commercial 12-month tranche and zero Industrial tranches. For Penelec offerings, FES won 1 Residential 5-month tranche, 1 Residential 24-month tranche, zero Commercial 5-month tranches, zero Commercial 12-month tranches and zero Industrial tranches. FES entered into separate Supplier Master Agreements (SMA) to provide capacity, energy, ancillary services, and congestion costs with Met-Ed and Penelec for each product won. Under the terms and conditions of the SMA, Met-Ed and Penelec are responsible for payment of noncontrollable transmission costs billed by PJM.
On January 18 to 20, 2011 FES participated in a descending clock auction for POLR service administered by Met-Ed, Penelec, and Penn Power and their consultant, NERA for the following tranche products and delivery periods: Residential 12-month, Residential 24-month, Commercial 12-month and Industrial 12-month. All 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 3 Residential 12-month tranches, 4 Residential 24-month tranches, 6 Commercial 12-month tranches and 11 Industrial tranches. Penelec offered 3 Residential 12-month tranches, 2 Residential 24-month tranches, 5 Commercial 12-month tranches and 11 Industrial tranches. Penn Power offered 2 Residential 12-month tranches, 1 Residential 24-month tranche, 3 Commercial 12-month tranches and 3 Industrial tranches.
For Met-Ed offerings, FES won 1 Commercial 12-month tranche and zero for the remaining products. For Penelec and Penn Power offerings, FES won no tranches. FES entered into a SMA to provide capacity, energy, ancillary services, and congestion costs with Met-Ed for the product won. Under the terms and conditions of the SMA, Met-Ed is responsible for payment of noncontrollable transmission costs billed by PJM.
Reliability Initiatives
Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC and ATSI. The NERC, as the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.
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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. At this time, FirstEnergy is unable to predict the outcome of this investigation.
ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
The Sammis, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NOx and SO2 emissions through the installation of pollution control devices or repowering. OE and Penn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement.
In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in those three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy.
In January 2009, the EPA issued a NOV to GenOn alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986 and also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that “modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. In January, 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on alleged “modifications” at the Homer City Power Station between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the State of New York intervened and have filed a separate complaint regarding the Homer City Station. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy Westside, Inc. is under dispute and Penelec is unable to predict the outcome of this matter.
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In January 2011, a complaint was filed against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’s air emissions. The complaint was also filed against the former co-owner, NYSEG and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. The complaint also seeks certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR, and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the CATR to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management continues to assess the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. In August 2010, for example, management decided to idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. On January 20, 2011, the U.S. District Court for the District of Columbia denied a motion by the EPA for an extension of the deadline to issue final rules, ordering the EPA to issue such rules by February 21, 2011. The EPA also entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
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Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. On December 6, 2010, the U.S. Supreme Court granted a writ of certiorari to the Second Circuit inConnecticut v. AEP. Briefing and oral argument are expected to be completed in early 2011 and a decision issued in or around June 2011. While FirstEnergy is not a party to this litigation, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy’s operations.
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The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’s cooling water system). The EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On November 19, 2010, the Ohio EPA issued a permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In June 2008, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of December 31, 2010, based on estimates of the total costs of cleanup, the Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $32 million) have been accrued through December 31, 2010. Included in the total are accrued liabilities of approximately $64 million for environmental remediation of former MGPs and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
OTHER LEGAL PROCEEDINGS
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting for the Court’s decision.
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Litigation Relating to the Proposed Allegheny Merger
In connection with the proposed merger (Note 22), purported shareholders of Allegheny have filed putative shareholder class action and/or derivative lawsuits against Allegheny and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and it was approved and became final on January 12, 2011. The separate Pennsylvania federal and state proceedings were dismissed on January 14, 2011 and January 18, 2011, respectively. The above shareholder actions have been fully and finally resolved.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the CRDM nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.
On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any, that the NRC takes in response to the UCS request have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2010, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and its effects on particular businesses and the economy could also affect the values of the nuclear decommissioning trusts. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated the decommissioning of FirstEnergy’s nuclear facilities. As a result, FirstEnergy’s decommissioning funding obligations are expected to increase. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.
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On August 27, 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. On December 27 and 28, 2010, a group of petitioners filed a request for hearing contending that FENOC failed to adequately consider wind or solar generation, or some combination thereof, as an alternative to license extension at Davis-Besse. They further argued FENOC had failed to adequately assess the cost of a severe accident at Davis-Besse. FENOC and the NRC staff responded to this pleading on January 21, 2011, demonstrating that none of the petitioners’ arguments were admissible contentions under the National Environmental Policy Act or NRC regulations. An Atomic Safety and Licensing Board panel is expected to determine whether a hearing is necessary.
Ohio Legal Matters
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.
CRITICAL ACCOUNTING POLICIES
FirstEnergy prepares consolidated financial statements in accordance with GAAP. Application of these principles often requires a high degree of judgment, estimates and assumptions that affect financial results. All of FirstEnergy assets are subject to specific risks and uncertainties and are regularly reviewed for impairment. FirstEnergy’s more significant accounting policies are described below.
Revenue Recognition
FirstEnergy follows the accrual method of accounting for revenues, recognizing revenue for electricity that has been delivered to customers but not yet billed through the end of the accounting period. The determination of electricity sales to individual customers is based on meter readings, which occur on a systematic basis throughout the month. At the end of each month, electricity delivered to customers since the last meter reading is estimated and a corresponding accrual for unbilled sales is recognized. The determination of unbilled sales and revenues requires management to make estimates regarding electricity available for retail load, transmission and distribution line losses, demand by customer class, applicable billing demands, weather-related impacts, number of days unbilled and tariff rates in effect within each customer class.
Regulatory Accounting
FirstEnergy’s energy delivery services segment is subject to regulation that sets the prices (rates) the Utilities are permitted to charge customers based on costs that the regulatory agencies determine the Utilities are permitted to recover. At times, regulators permit the future recovery through rates of costs that would be currently charged to expense by an unregulated company. This ratemaking process results in the recording of regulatory assets based on anticipated future cash inflows. FirstEnergy regularly reviews these assets to assess their ultimate recoverability within the approved regulatory guidelines. Impairment risk associated with these assets relates to potentially adverse legislative, judicial or regulatory actions in the future.
Pension and Other Postretirement Benefits Accounting
FirstEnergy’s reported costs of providing noncontributory qualified and non-qualified defined pension benefits and OPEB benefits other than pensions are dependent upon numerous factors resulting from actual plan experience and certain assumptions.
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Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions FirstEnergy makes to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes to key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs.
In accordance with GAAP, changes in pension and OPEB obligations associated with these factors may not be immediately recognized as costs on the income statement, but generally are recognized in future years over the remaining average service period of plan participants. GAAP delays recognition of changes due to the long-term nature of pension and OPEB obligations and the varying market conditions likely to occur over long periods of time. As such, significant portions of pension and OPEB costs recorded in any period may not reflect the actual level of cash benefits provided to plan participants and are significantly influenced by assumptions about future market conditions and plan participants’ experience.
FirstEnergy recognizes the overfunded or underfunded status of the defined benefit pension and other postretirement benefit plans on the balance sheet and recognize changes in funded status in the year in which the changes occur through other comprehensive income. The underfunded status of FirstEnergy’s qualified and non-qualified pension and OPEB plans at December 31, 2010 was $1.7 billion. FirstEnergy voluntarily intends to contribute $250 million to its pension plan in 2011.
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed discount rates for pension were 5.50%, 6.00% and 7.00% for December 31, 2010, 2009 and 2008, respectively. The assumed discount rates for OPEB were 5.00%, 5.75% and 7.0% as of December 31, 2010, 2009 and 2008, respectively.
FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2010, FirstEnergy’s qualified pension and OPEB plan assets earned $492 million or 10.1% compared to amounts earned of $570 million or 13.6% in 2009. The qualified pension and OPEB costs in 2010 and 2009 were computed using an assumed 8.5% and 9.0% rate of return, respectively, on plan assets which generated $397 million and $379 million of expected returns on plan assets, respectively. The expected return of pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets are deferred and amortized and will increase or decrease future net periodic pension and OPEB cost, respectively.
FirstEnergy’s qualified and non-qualified pension and OPEB net periodic benefit cost was $138 million in 2010 compared to $197 million in 2009 and credits of $116 million in 2008. FirstEnergy expects the 2011 qualified and non-qualified pension and OPEB costs (including amounts capitalized) to be $103 million.
On June 2, 2009, FirstEnergy amended the health care benefits plan for all employees and retirees eligible that participate in that plan. The amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. On September 2, 2009, the Utilities and ATSI made a combined $500 million voluntary contribution to their qualified pension plan. Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure the qualified pension plan as of August 31, 2009. In the third quarter of 2009, FirstEnergy also incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to a liability created by the VERO offered by FirstEnergy to qualified employees. The special termination benefits of the VERO included additional health care coverage subsidies paid by FirstEnergy to those qualified employees who elected to retire. A total of 715 employees accepted the VERO.
Health care cost trends continue to increase and will affect future OPEB costs. The 2010 composite health care trend rate assumptions were approximately 8-9%, compared to 8.5-10% in 2009, gradually decreasing to 5% in later years. In determining FirstEnergy’s trend rate assumptions, included are the specific provisions of FirstEnergy’s health care plans, the demographics and utilization rates of plan participants, actual cost increases experienced in FirstEnergy’s health care plans, and projections of future medical trend rates. The effect on the pension and OPEB costs from changes in key assumptions are as follows:
Increase in Costs from Adverse Changes in Key Assumptions
| Assumption | Adverse Change | Pension | OPEB | Total | ||||||||||||
| (In millions) | ||||||||||||||||
| Discount rate | Decrease by 0.25% | $ | 13 | $ | 1 | $ | 14 | |||||||||
| Long-term return on assets | Decrease by 0.25% | $ | 12 | $ | 1 | $ | 13 | |||||||||
| Health care trend rate | Increase by 1% | N/A | $ | 4 | $ | 4 | ||||||||||
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Emission Allowances
FirstEnergy holds emission allowances for SO2 and NOX in order to comply with programs implemented by the EPA designed to regulate emissions of SO2 and NOX produced by power plants. Emission allowances are either granted by the EPA at zero cost or are purchased at fair value as needed to meet emission requirements. Emission allowances are not purchased with the intent of resale. Emission allowances eligible to be used in the current year are recorded in materials and supplies inventory at the lesser of weighted average cost or market value. Emission allowances eligible for use in future years are recorded as other investments. FirstEnergy recognizes emission allowance costs as fuel expense during the periods that emissions are produced by generating facilities. Excess emission allowances that are not needed to meet emission requirements may be sold and are reported as a reduction to other operating expenses.
Long-Lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such an asset may not be recoverable. The recoverability of a long-lived asset is measured by comparing the asset’s carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
Asset Retirement Obligations
FirstEnergy recognizes an ARO for the future decommissioning of FirstEnergy’s nuclear power plants and future remediation of other environmental liabilities associated with long-lived assets. The ARO liability represents an estimate of the fair value of the current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plants’ current license, settlement based on an extended license term and expected remediation dates.
Income Taxes
We record income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled.
FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, a more-likely-than-not recognition criterion and a measurement attribute that measures the position as the largest amount of tax benefit that is greater than 50% likely of being ultimately realized upon ultimate settlement. If it is not more likely than not that the benefit will be sustained on its technical merits, no benefit will be recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes.
Goodwill
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. Impairment is indicated and a loss is recognized if the implied fair value of a reporting unit’s goodwill is less than the carrying value of its goodwill.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
See Note 16 to the consolidated financial statements for discussion of new accounting pronouncements.
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FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities, and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues during 2010 were derived from sales to individual retail customers, sales to communities in the form of government aggregation programs, the sale of electricity to Met-Ed and Penelec to meet all of their POLR and default service requirements, and its participation in affiliated and non-affiliated POLR auctions. FES sales were primarily concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. Beginning in 2011, FES will not be required to supply Met-Ed and Penelec’s POLR and default service requirements as Met-Ed and Penelec will procure power under their Default Service Plans in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.
The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions and weather conditions.
For additional information with respect to FES, please see the information contained in FirstEnergy Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased to $269 million in 2010 compared to $577 million in 2009. The decrease in net income was primarily due to $384 million of impairment charges ($240 million net of tax) in 2010. In addition, FES sold a 6.65% participation interest in OVEC in 2010 compared to a 9% interest in 2009, accounting for $105 million of the reduction in net income. Investment income from nuclear decommissioning trusts was also lower in 2010. These reductions were partially offset by an increase in sales margins.
Revenues
Excluding the impact of the OVEC sale in both years, total revenues increased $1,267 million in 2010 compared to the same period in 2009, primarily due to an increase in direct and government aggregation sales and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and other wholesale sales.
The increase in revenues resulted from the following sources:
| Increase | ||||||||||||
| Revenues by Type of Service | 2010 | 2009 | (Decrease) | |||||||||
| (In millions) | ||||||||||||
| Direct and Government Aggregation | $ | 2,494 | $ | 779 | $ | 1,715 | ||||||
| POLR | 2,436 | 2,863 | (427 | ) | ||||||||
| Other Wholesale | 550 | 632 | (82 | ) | ||||||||
| Transmission | 77 | 73 | 4 | |||||||||
| RECs | 74 | 17 | 57 | |||||||||
| Sale of OVEC participation interest | 85 | 252 | (167 | ) | ||||||||
| Other | 112 | 112 | — | |||||||||
Total Revenues | $ | 5,828 | $ | 4,728 | $ | 1,100 | ||||||
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Direct and government aggregation revenues increased by $1.7 billion due to the acquisition of new commercial and industrial customers as well as from new government aggregation contracts with communities in Ohio that provide generation to 1.5 million residential and small commercial customers at the end of 2010 compared to 600,000 of such customers at the end of 2009. Increases in direct sales were partially offset by lower unit prices. Sales to residential and small commercial customers were also bolstered by summer weather in the delivery area that was significantly warmer than in 2009.
The decrease in POLR revenues of $427 million was due to lower sales volumes and unit prices to the Ohio Companies, partially offset by increased sales volumes and higher unit prices to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies in 2010 reflected the results of the May 2009 CBP. The increased revenues to the Pennsylvania Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices that were slightly higher than in 2009.
Other wholesale revenues decreased $82 million due to reduced volumes, partially offset by higher prices. Lower sales volumes in MISO were due to available capacity serving increased retail sales in Ohio, partially offset by increased sales under bilateral agreements in PJM.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| Increase | ||||
| Source of Change in Direct and Government Aggregation | (Decrease) | |||
| (In millions) | ||||
| Direct Sales: | ||||
| Effect of increase in sales volumes | $ | 1,083 | ||
| Change in prices | (82 | ) | ||
| 1,001 | ||||
| Government Aggregation | ||||
| Effect of increase in sales volumes | 704 | |||
| Change in prices | 10 | |||
| 714 | ||||
Net Increase in Direct and Government Aggregation Revenues | $ | 1,715 | ||
| Increase | ||||
| Source of Change in Wholesale Revenues | (Decrease) | |||
| (In millions) | ||||
| POLR: | ||||
| Effect of decrease in sales volumes | $ | (153 | ) | |
| Change in prices | (274 | ) | ||
| (427 | ) | |||
| Other Wholesale: | ||||
| Effect of decrease in sales volumes | (105 | ) | ||
| Change in prices | 23 | |||
| (82 | ) | |||
Net Decrease in Wholesale Revenues | $ | (509 | ) | |
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Expenses
Total expenses increased $1.5 billion in 2010 compared to 2009. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in 2010 compared to 2009:
| Increase | ||||
| Source of Change in Fuel and Purchased Power | (Decrease) | |||
| (In millions) | ||||
| Fossil Fuel: | ||||
| Change due to increased unit costs | $ | 34 | ||
| Change due to volume consumed | 207 | |||
| 241 | ||||
| Nuclear Fuel: | ||||
| Change due to increased unit costs | 29 | |||
| Change due to volume consumed | 5 | |||
| 34 | ||||
| Non-affiliated Purchased Power: | ||||
| Power contract mark-to-market adjustment | (168 | ) | ||
| Change due to decreased unit costs | (139 | ) | ||
| Change due to volume purchased | 896 | |||
| 589 | ||||
| Affiliated Purchased Power: | ||||
| Change due to increased unit costs | 101 | |||
| Change due to volume purchased | 47 | |||
| 148 | ||||
Net Increase in Fuel and Purchased Power Costs | $ | 1,012 | ||
Fossil fuel costs increased $241 million in 2010 compared to 2009. Increased volumes consumed in 2010 were due to higher sales to direct and government aggregation customers as well as to improved economic conditions. The higher unit prices reflect higher coal transportation charges in 2010 compared to last year. Nuclear fuel costs increased $34 million primarily due to the replacement of nuclear fuel at higher unit costs following the refueling outages that occurred in 2009 and 2010.
Non-affiliated purchased power costs increased $589 million. Increased volumes purchased primarily relate to the assumption of a 1,300 MW third party contract from Met-Ed and Penelec. Affiliated purchased power increased $148 million primarily due to higher unit costs combined with higher volumes purchased from affiliated companies.
Other operating expenses increased $96 million in 2010 compared to 2009, primarily due to the significant growth in FES’ retail business. Costs increased for transmission expenses, contractor expenses, associated company billings from affiliated service companies, uncollectible customer accounts and agent fees. Those increases were partially offset by reduced generating plant operating costs due to lower labor and one less nuclear refueling outage in 2010.
In 2010 impairment charges of long-lived assets increased expenses by $384 million ($240 million net of tax) related to operational changes at certain smaller coal-fired units in response to the continued slow economy, lower demand for electricity as well as uncertainty related to proposed new federal environmental regulations.
Depreciation expense decreased $16 million principally due to reduced depreciable property associated with the impairments described above and sale of the Sumpter plant in early 2010.
General taxes increased $7 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense in 2010 was $94 million higher than the same period in 2009, primarily due to a decrease in nuclear decommissioning trust investment income of $66 million and a $32 million increase in interest expense (net of capitalized interest) from new long-term debt issued in late 2009 combined with the restructuring of outstanding PCRBs that occurred throughout 2009 and 2010.
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Market Risk Information
FES uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FES is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices associated with electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FES uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FES relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FES uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 6 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of December 31, 2010 are summarized by contract year in the following table:
| Source of Information- | ||||||||||||||||||||||||||||
| Fair Value by Contract Year | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Prices actively quoted(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Other external sources(2) | (115 | ) | 6 | 4 | 7 | — | — | (98 | ) | |||||||||||||||||||
Prices based on models | — | — | — | — | — | (9 | ) | (9 | ) | |||||||||||||||||||
Total | $ | (115 | ) | $ | 6 | $ | 4 | $ | 7 | $ | — | $ | (9 | ) | $ | (107 | ) | |||||||||||
| (1) | Represents futures and options traded on the New York Mercantile Exchange. | |
| (2) | Primarily represents contracts based on broker and IntercontinentalExchange quotes. |
FES performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $16 million ($10 million net of tax) during the next 12 months.
Interest Rate Risk
FES’ exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for FES’ investment portfolio and debt obligations.
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Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 994 | $ | 994 | $ | 994 | ||||||||||||||||||||||||||
| Average interest rate | 10.1 | % | 10.1 | % | ||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 158 | $ | 68 | $ | 75 | $ | 99 | $ | 450 | $ | 2,650 | $ | 3,500 | $ | 3,624 | ||||||||||||||||
| Average interest rate | 4.6 | % | 9 | % | 9 | % | 7.3 | % | 5.1 | % | 5.2 | % | 5.3 | % | ||||||||||||||||||
| Variable rate | $ | 779 | $ | 779 | $ | 779 | ||||||||||||||||||||||||||
| Average interest rate | 0.3 | % | 0.3 | % | ||||||||||||||||||||||||||||
| Short-term Borrowings: | $ | 12 | $ | 12 | $ | 12 | ||||||||||||||||||||||||||
| Average interest rate | 0.6 | % | 0.6 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy NGC’s nuclear decommissioning obligations. Included in FES’s nuclear decommissioning trust are fixed income and short-term investments carried at a market value of approximately $1,139 million as of December 31, 2010. NGC recognizes in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts as other-than-temporary impairments. A decline in the value of the nuclear decommissioning trusts or a significant escalation in estimated decommissioning costs could result in additional funding requirements. FES continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
Credit Risk
Credit risk is the risk of an obligor’s failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FES engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FES maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FES aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of December 31, 2010, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 3.3% of FES total approved credit risk.
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OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier.
For additional information with respect to OE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $35 million in 2010 compared to 2009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues and investment income.
Revenues
Revenues decreased $681 million, or 27%, in 2010 compared to 2009 due primarily to a decrease in generation revenues.
Distribution revenues increased $6 million in 2010 compared to 2009, due to higher residential revenues, partially offset by lower commercial and industrial revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010. Residential distribution revenues increased due to higher average unit prices resulting from the 2009 ESP and higher KWH deliveries resulting from the warmer conditions (cooling degree days increased 88% in OE’s service territory). Increased industrial deliveries were the result of higher KWH deliveries to major steel customers and automotive customers, reflecting improving economic conditions.
Changes in distribution KWH deliveries and revenues in 2010 compared to 2009 are summarized in the following tables:
| Distribution KWH Deliveries | Increase | |||
| Residential | 5.5 | % | ||
| Commercial | 2.6 | % | ||
| Industrial | 9.5 | % | ||
Increase in Distribution Deliveries | 5.8 | % | ||
| Increase | ||||
| Distribution Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 33 | ||
| Commercial | (7 | ) | ||
| Industrial | (20 | ) | ||
Net Increase in Distribution Revenues | $ | 6 | ||
Retail generation revenues decreased $680 million primarily due to lower KWH sales in all customer classes. Lower KWH sales resulted principally from a 36% increase in customer shopping in 2010. That sales reduction was partially offset by increased weather-related usage in 2010 as described above. Lower average unit pricing also contributed to the decrease as lower unit prices in the residential class were partially offset by higher unit prices in the commercial and industrial classes.
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Changes in retail generation KWH sales and revenues in 2010 compared to 2009 are summarized in the following tables:
| Retail Generation KWH Sales | Decrease | ||||
| Residential | (26.0 | )% | |||
| Commercial | (58.0 | )% | |||
| Industrial | (58.2 | )% | |||
Decrease in Retail Generation Sales | (43.3 | )% | |||
| Retail Generation Revenues | Decrease | |||
| (In millions) | ||||
| Residential | $ | (216 | ) | |
| Commercial | (266 | ) | ||
| Industrial | (198 | ) | ||
Decrease in Retail Generation Revenues | $ | (680 | ) | |
Expenses
Total expenses decreased $752 million in 2010 compared to 2009. The following table presents changes from the prior period by expense category:
| Increase | ||||
| Expenses — Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | (635 | ) | |
| Other operating expenses | (97 | ) | ||
| Provision for depreciation | (1 | ) | ||
| Amortization of regulatory assets, net | (31 | ) | ||
| General taxes | 12 | |||
Net Decrease in Expenses | $ | (752 | ) | |
Purchased power costs decreased in 2010 compared to 2009, primarily due to lower KWH purchases resulting from reduced requirements in 2010 and slightly lower unit costs. The decrease in other operating costs for 2010 was primarily due to lower MISO transmission expenses ($48 million) (assumed by third party suppliers beginning June 1, 2009), the absence in 2010 of costs associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP ($18 million) and decreased labor expenses ($12 million). The amortization of regulatory assets decreased primarily due to lower MISO transmission cost amortization, partially offset by increased recovery of other regulatory assets. The increase in general taxes was primarily due to higher Ohio KWH taxes in 2010 as compared to 2009 and a $7.1 million Ohio KWH tax adjustment recognized in 2009 related to prior periods.
Other Expense
Other expense increased $21 million in 2010 compared to 2009, primarily due to lower nuclear decommissioning trust investment income.
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Interest Rate Risk
OE’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for OE’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 28 | $ | 31 | $ | 37 | $ | 42 | $ | 37 | $ | 138 | $ | 313 | $ | 365 | ||||||||||||||||
| Average interest rate | 8.7 | % | 8.7 | % | 8.8 | % | 8.8 | % | 8.9 | % | 4 | % | 6.7 | % | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 1,159 | $ | 1,159 | $ | 1,321 | ||||||||||||||||||||||||||
| Average interest rate | 6.9 | % | 6.9 | % | ||||||||||||||||||||||||||||
| Short-term Borrowings: | $ | 142 | $ | 142 | $ | 142 | ||||||||||||||||||||||||||
| Average interest rate | 0.5 | % | 0.5 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy nuclear decommissioning obligations. Included in OE’s nuclear decommissioning trust are fixed income and short-term investments carried at a market value of approximately $126 million as of December 31, 2010. OE recognizes in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trust as other-than-temporary impairments. A decline in the value of the nuclear decommissioning trust or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees. OE continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also procures generation services for those customers electing to retain CEI as their power supplier.
For additional information with respect to CEI, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $84 million in 2010 compared to 2009. The increase in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009 and decreased purchased power costs, other operating costs and amortization, partially offset by decreased revenues and deferrals of new regulatory assets.
Revenues
Revenues decreased $455 million, or 27%, in 2010 compared to 2009 due to lower retail generation and distribution revenues.
Distribution revenues decreased $87 million in 2010 compared to 2009 due to lower average unit prices for all customer classes offset by increased KWH deliveries in all sectors. The lower average unit prices were the result of lower transition rates in 2010. Higher residential deliveries resulted from increased weather-related usage in 2010, reflecting a 74% increase in cooling degree days, partially offset by a 5% decrease in heating degree days. Increased industrial deliveries were the result of higher KWH deliveries to major steel customers (101%) and automotive customers (6%), reflecting improved economic conditions.
Changes in distribution KWH deliveries and revenues in the 2010 compared to 2009 are summarized in the following tables:
| Distribution KWH Deliveries | Increase | |||
| Residential | 5.5 | % | ||
| Commercial | 2.9 | % | ||
| Industrial | 10.9 | % | ||
Increase in Distribution Deliveries | 7.0 | % | ||
| Distribution Revenues | Decrease | |||
| (In millions) | ||||
| Residential | $ | (4 | ) | |
| Commercial | (31 | ) | ||
| Industrial | (52 | ) | ||
Decrease in Distribution Revenues | $ | (87 | ) | |
Retail generation revenues decreased $359 million in 2010 as compared to 2009 primarily due to lower KWH sales to all customer classes. Reduced KWH sales were primarily the result of a 45% increase in customer shopping. Lower KWH sales to residential customers were partially offset by increased KWH deliveries resulting from the previously discussed warmer weather. Decreased volumes were partially offset by higher average unit prices in all customer classes. Retail generation prices increased in 2010 as a result of the CBP auction for the service period beginning June 1, 2009.
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Changes in retail generation sales and revenues in 2010 compared to 2009 are summarized in the following tables:
| Retail Generation KWH Sales | Decrease | |||
| Residential | (50.3 | )% | ||
| Commercial | (67.2 | )% | ||
| Industrial | (44.5 | )% | ||
Decrease in Retail Generation Sales | (51.7 | )% | ||
| Retail Generation Revenues | Decrease | |||
| (In millions) | ||||
| Residential | $ | (96 | ) | |
| Commercial | (134 | ) | ||
| Industrial | (129 | ) | ||
Decrease in Retail Generation Revenues | $ | (359 | ) | |
Expenses
Total expenses decreased $589 million in 2010 compared to 2009. The following table presents changes from the prior period by expense category:
| Increase | ||||
| Expenses - Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | (490 | ) | |
| Other operating costs | (31 | ) | ||
| Amortization of regulatory assets, net | (201 | ) | ||
| Deferral of new regulatory assets | 135 | |||
| General taxes | (2 | ) | ||
Net Decrease in Expenses | $ | (589 | ) | |
Purchased power costs decreased in 2010 primarily due to the previously discussed lower KWH sales requirements. Other operating costs decreased due to lower transmission expenses (assumed by third party suppliers beginning June 1, 2009), labor and employee benefit expenses and the absence in 2010 of certain costs incurred in 2009 associated with regulatory obligations for economic development and energy efficiency programs. Decreased amortization of regulatory assets was due primarily to the 2009 impairment of CEI’s Extended RTC regulatory asset of $216 million in accordance with the PUCO-approved ESP. A decrease in the deferral of new regulatory assets was primarily due to CEI’s contemporaneous recovery of purchased power costs in 2010. General taxes decreased primarily due to a 2010 favorable property tax settlement in Ohio.
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Interest Rate Risk
CEI has little exposure to fluctuations in market interest rates because most of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for CEI’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 53 | $ | 66 | $ | 75 | $ | 80 | $ | 50 | $ | 16 | $ | 340 | $ | 381 | ||||||||||||||||
| Average interest rate | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 8 | % | 7.7 | % | ||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 22 | $ | 325 | $ | 26 | $ | 24 | $ | 1,456 | $ | 1,853 | $ | 2,035 | ||||||||||||||||||
| Average interest rate | 7.7 | % | 5.8 | % | 7.7 | % | 7.7 | % | 6.8 | % | 6.7 | % | ||||||||||||||||||||
| Short-term Borrowings: | $ | 106 | $ | 106 | $ | 106 | ||||||||||||||||||||||||||
| Average interest rate | 1.9 | % | 1.9 | % | ||||||||||||||||||||||||||||
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THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Off-Balance Sheet Arrangements, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased by $9 million in 2010 compared to 2009. The increase was primarily due to decreased net amortization of regulatory assets, purchased power and other operating costs, partially offset by an increase in interest expense and decreases in revenues and investment income.
Revenues
Revenues decreased $317 million, or 38%, in 2010 compared to 2009, primarily due to lower retail generation and distribution revenues, partially offset by an increase in wholesale generation revenues.
Distribution revenues decreased $23 million in 2010 compared to 2009, primarily due to lower unit prices, partially offset by higher KWH deliveries to all customer classes. Lower unit prices are primarily due to lower transmission rates. Higher KWH deliveries were influenced by weather-related usage in 2010, reflecting an 85% increase in cooling degree days in TE’s service territory, partially offset by a 6% decrease in heating degree days. Increased industrial deliveries were the result of higher KWH deliveries to major automotive customers and steel customers, reflecting improved economic conditions.
Changes in distribution KWH deliveries and revenues in 2010 compared to 2009 are summarized in the following tables:
| Distribution KWH Deliveries | Increase | |||
| Residential | 7.6 | % | ||
| Commercial | 3.7 | % | ||
| Industrial | 12.3 | % | ||
Increase in Distribution Deliveries | 8.7 | % | ||
| Increase | ||||
| Distribution Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 1 | ||
| Commercial | (6 | ) | ||
| Industrial | (18 | ) | ||
Net Decrease in Distribution Revenues | $ | (23 | ) | |
Retail generation revenues decreased $307 million in 2010 compared to 2009, primarily due to lower KWH sales to all customer classes and lower unit prices to industrial customers. Lower KWH sales to all customer classes were primarily the result of a 48% increase in customer shopping in 2010, partially offset by higher KWH deliveries resulting from the weather conditions described above. Lower unit prices for industrial customers were primarily due to the absence of TE’s fuel cost recovery and rate stabilization riders that were effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.
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Changes in retail generation KWH sales and revenues in 2010 compared to 2009 are summarized in the following tables:
| Retail Generation KWH Sales | Decrease | |||
| Residential | (39.8 | )% | ||
| Commercial | (69.6 | )% | ||
| Industrial | (55.3 | )% | ||
Decrease in Retail Generation Sales | (54.7 | )% | ||
| Retail Generation Revenues | Decrease | |||
| (In millions) | ||||
| Residential | $ | (60 | ) | |
| Commercial | (112 | ) | ||
| Industrial | (135 | ) | ||
Decrease in Retail Generation Revenues | $ | (307 | ) | |
Wholesale revenues increased $9 million in 2010 compared to 2009, primarily due to an increase in KWH sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2 and higher unit prices.
Expenses
Total expenses decreased $353 million in 2010 compared to 2009. The following table presents changes from the prior period by expense category:
| Increase | ||||
| Expenses - Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | (285 | ) | |
| Other operating expenses | (34 | ) | ||
| Provision for depreciation | 1 | |||
| Amortization (deferral) of regulatory assets, net | (39 | ) | ||
| General taxes | 4 | |||
Net Decrease in Expenses | $ | (353 | ) | |
Purchased power costs decreased in 2010 compared to 2009, due to lower volumes required as a result of decreased KWH sales. Other operating costs decreased primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009) and lower costs associated with regulatory obligations for economic development and energy efficiency programs. The amortization of regulatory assets decreased primarily due to PUCO-approved cost deferrals and lower MISO transmission cost amortization in 2010 compared to 2009. The increase in general taxes was primarily due to higher Ohio KWH taxes in 2010 as compared to 2009 and a $3.5 million Ohio KWH tax adjustment recognized in 2009 related to prior periods.
Other Expense
Other expense increased $17 million in 2010 compared to 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes and lower nuclear decommissioning trust investment income.
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Interest Rate Risk
TE has little exposure to fluctuations in market interest rates because most of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for TE’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 22 | $ | 25 | $ | 26 | $ | 24 | $ | 48 | $ | 145 | $ | 160 | ||||||||||||||||||
| Average interest rate | 7.7 | % | 7.7 | % | 7.7 | % | 7.7 | % | 5 | % | 6.8 | % | ||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 600 | $ | 600 | $ | 653 | ||||||||||||||||||||||||||
| Average interest rate | 6.7 | % | 6.7 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy nuclear decommissioning obligations. Included in TE’s nuclear decommissioning trust are fixed income and short-term investments carried at a market value of approximately $76 million as of December 31, 2010. TE recognizes in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trust as other-than-temporary impairments. A decline in the value of the nuclear decommissioning trust or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees. TE continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
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JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
JCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. JCP&L conducts business in New Jersey, providing regulated electric transmission and distribution services. JCP&L also procures generation services for franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $22 million in 2010 compared to 2009. The increase was primarily due to higher revenues, lower purchased power costs and decreased net amortization of regulatory assets, partially offset by increased other operating costs.
Revenues
Revenues increased by $34 million, or 1%, in 2010 compared with 2009. The increase in revenues was primarily due to higher distribution, wholesale generation and other revenues, partially offset by a decrease in retail generation revenues.
Distribution revenues increased by $62 million in 2010 compared to 2009, due to higher KWH deliveries in all customer classes. Increased usage was due to warmer weather and improved economic conditions in JCP&L’s service territory. Decreased composite unit prices in the commercial and industrial classes partially offset the increased volume.
Changes in distribution KWH deliveries and revenues in 2010, compared to 2009, are summarized in the following tables:
| Distribution KWH Sales | Increase | |||
| Residential | 8.5 | % | ||
| Commercial | 2.6 | % | ||
| Industrial | 1.6 | % | ||
Increase in Distribution Deliveries | 5.0 | % | ||
| Increase | ||||
| Distribution Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 58 | ||
| Commercial | 5 | |||
| Industrial | (1 | ) | ||
Net Increase in Distribution Revenues | $ | 62 | ||
In 2010, retail generation revenues decreased by $72 million due to lower KWH sales to the commercial and industrial classes, partially offset by higher KWH sales to the residential class. Lower sales to the commercial and industrial classes were primarily due to an increase in the number of shopping customers. Higher KWH sales to the residential class reflected increased weather-related usage resulting from a 60% increase in cooling degree days in 2010, partially offset by a 5% decrease in heating degree days during the same period.
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Changes in retail generation KWH sales and revenues in 2010, compared to 2009, are summarized in the following tables:
| Increase | ||||
| Retail Generation KWH Sales | (Decrease) | |||
| Residential | 6.8 | % | ||
| Commercial | (26.4 | )% | ||
| Industrial | (22.4 | )% | ||
Net Decrease in Retail Generation Sales | (6.2 | )% | ||
| Increase | ||||
| Retail Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 85 | ||
| Commercial | (146 | ) | ||
| Industrial | (11 | ) | ||
Net Decrease in Retail Generation Revenues | $ | (72 | ) | |
Wholesale generation revenues increased $27 million in 2010 compared to 2009, due primarily to higher wholesale energy prices.
Other revenues increased $17 million in 2010 compared to 2009, primarily due to an increase in transition bond revenues as a result of higher KWH deliveries in all customer classes.
Expenses
Total expenses decreased $29 million in 2010 compared to 2009. The following table presents changes from the prior year by expense category:
| Increase | ||||
| Expenses - Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | (46 | ) | |
| Other operating costs | 34 | |||
| Provision for depreciation | 4 | |||
| Amortization of regulatory assets, net | (23 | ) | ||
| General taxes | 2 | |||
Net Decrease in Expenses | $ | (29 | ) | |
Purchased power costs decreased in 2010 primarily from reduced requirements due to lower retail generation sales. Other operating costs increased in 2010 primarily due to major storm clean up costs, partially offset by a favorable collective bargaining settlement that reduced expenses by $7 million in the second quarter of 2010. The amortization of regulatory assets decreased in 2010 primarily due to the deferral of storm costs.
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Market Risk Information
JCP&L uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
JCP&L is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, JCP&L uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, JCP&L relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. JCP&L uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2010 are summarized by contract year in the following table:
| Source of Information- | ||||||||||||||||||||||||||||
| Fair Value by Contract Year | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Prices actively quoted(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Other external sources(2) | (94 | ) | (47 | ) | (42 | ) | (34 | ) | — | — | (217 | ) | ||||||||||||||||
| Prices based on models | — | — | — | — | (11 | ) | 3 | (8 | ) | |||||||||||||||||||
Total(3) | $ | (94 | ) | $ | (47 | ) | $ | (42 | ) | $ | (34 | ) | $ | (11 | ) | $ | 3 | $ | (225 | ) | ||||||||
| (1) | Represents futures and options traded on the New York Mercantile Exchange. | |
| (2) | Primarily represents contracts based on broker and IntercontinentalExchange quotes. | |
| (3) | Includes $225 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings. |
JCP&L performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on JCP&L’s consolidated financial position or cash flows as of December 31, 2010. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would not have a material effect on JCP&L’s net income for the next 12 months.
Interest Rate Risk
JCP&L’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for JCP&L’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 290 | $ | 290 | $ | 290 | ||||||||||||||||||||||||||
| Average interest rate | 3.7 | % | 3.7 | % | ||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 32 | $ | 34 | $ | 36 | $ | 39 | $ | 41 | $ | 1,628 | $ | 1,810 | $ | 1,962 | ||||||||||||||||
| Average interest rate | 5.6 | % | 5.7 | % | 5.7 | % | 5.9 | % | 6 | % | 6.1 | % | 6 | % | ||||||||||||||||||
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Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy nuclear decommissioning obligations. Included in JCP&L’s nuclear decommissioning trust are fixed income, equity securities and short-term investments carried at a market value of approximately $185 million as of December 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $10 million reduction in fair value as of December 31, 2010. The decommissioning trust of JCP&L is subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. A decline in the value of the nuclear decommissioning trust or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2010, $3 million was contributed to the JCP&L’s nuclear decommissioning trust to comply with regulatory requirements. JCP&L continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
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METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed purchased its POLR and default service requirements from FES through a fixed-price wholesale power sales agreement in 2010. Beginning in 2011, Met-Ed procures power under its Default Service Plan in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.
As authorized by Met-Ed’s Board of Directors, Met-Ed repurchased 117,620 shares of the Company’s common stock from its parent, FirstEnergy, for $150 million on January 28, 2011.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $2 million, or 4%, in 2010. The increase was primarily due to increased revenues and decreased amortization of net regulatory assets, partially offset by increased purchased power and other operating expenses.
Revenues
Revenue increased $130 million, or 8%, in 2010 compared to 2009, reflecting higher distribution and generation revenues, partially offset by a decrease in transmission revenues.
Distribution revenues increased $86 million in 2010 compared to 2009, primarily due to higher rates resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2010, partially offset by lower CTC rates for the residential class. Higher KWH deliveries to industrial customers were due to improved economic conditions in Met-Ed’s service territory. Higher residential and commercial KWH deliveries reflect increased weather-related usage due to a 59% increase in cooling degree days in 2010 compared to 2009, partially offset by a 5% decrease in heating degree days for the same period.
Changes in distribution KWH deliveries and revenues in 2010 compared to 2009 are summarized in the following tables:
| Distribution KWH Deliveries | Increase | |||
| Residential | 3.8 | % | ||
| Commercial | 3.1 | % | ||
| Industrial | 4.6 | % | ||
Increase in Distribution Deliveries | 3.8 | % | ||
| Distribution Revenues | Increase | |||
| (In millions) | ||||
| Residential | $ | 45 | ||
| Commercial | 28 | |||
| Industrial | 13 | |||
Increase in Distribution Revenues | $ | 86 | ||
In 2010, retail generation revenues increased $32 million due to higher composite unit prices and higher KWH sales to the residential customer class, partially offset by lower KWH sales to the commercial and industrial customer classes. The higher unit prices were primarily due to an increase in the generation rate effective January 1, 2010. Higher KWH sales to residential customers increased primarily due to weather-related usage described above. Increased customer shopping in the commercial and industrial classes drove the lower KWH sales to those classes.
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Changes in retail generation KWH sales and revenues in 2010 compared to 2009 are summarized in the following tables:
| Increase | ||||
| Retail Generation KWH Sales | (Decrease) | |||
| Residential | 3.8 | % | ||
| Commercial | (0.1 | )% | ||
| Industrial | (2.8 | )% | ||
Net Increase in Retail Generation Sales | 0.8 | % | ||
| Increase | ||||
| Retail Generation Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 36 | ||
| Commercial | — | |||
| Industrial | (4 | ) | ||
Net Increase in Retail Generation Revenues | $ | 32 | ||
Wholesale revenues increased $29 million in 2010 compared to 2009, primarily reflecting higher PJM capacity prices.
Transmission revenues decreased $19 million in 2010 compared to 2009 primarily due to decreased Financial Transmission Rights revenues. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased $112 million in 2010 compared to 2009. The following table presents changes from the prior year by expense category:
| Increase | ||||
| Expenses - Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | 54 | ||
| Other operating costs | 141 | |||
| Provision for depreciation | 1 | |||
| Amortization of regulatory assets, net | (84 | ) | ||
Net Increase in Expenses | $ | 112 | ||
Purchased power costs increased $54 million in 2010 compared to 2009 primarily due to an increase in unit costs. Other operating costs increased $141 million in 2010 compared to 2009 primarily due to higher transmission congestion and transmission loss expenses (see reference to deferral accounting above). The amortization of regulatory assets decreased $84 million in 2010 compared to 2009 primarily due to higher expense deferrals resulting from increased PJM transmission costs and reduced amortization due to decreasing regulatory asset balances.
Other Expense
Interest income decreased in 2010 compared to 2009 primarily due to reduced CTC stranded asset balances. That impact was partially offset by lower interest expense due to a $100 million debt repayment in March 2010 and reduced borrowings under the Revolving Credit Facility.
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Market Risk Information
Med-Ed uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
Met-Ed is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, Met-Ed uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Met-Ed relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Met-Ed uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2010 are summarized by contract year in the following table:
| Source of Information- | ||||||||||||||||||||||||||||
| Fair Value by Contract Year | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Prices actively quoted(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Other external sources(2) | (53 | ) | (48 | ) | (4 | ) | (2 | ) | — | — | (107 | ) | ||||||||||||||||
| Prices based on models | — | — | — | — | 24 | 83 | 107 | |||||||||||||||||||||
| Total | $ | (53 | ) | $ | (48 | ) | $ | (4 | ) | $ | (2 | ) | $ | 24 | $ | 83 | $ | — | ||||||||||
| (1) | Represents futures and options traded on the New York Mercantile Exchange. | |
| (2) | Primarily represents contracts based on broker and Intercontinental Exchange quotes. |
Met-Ed performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Met-Ed’s consolidated financial position or cash flows as of December 31, 2010. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would not have a material effect on Met-Ed’s net income for the next 12 months.
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Interest Rate Risk
Met-Ed’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Met-Ed’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 132 | $ | 132 | $ | 132 | ||||||||||||||||||||||||||
| Average interest rate | 3.4 | % | 3.4 | % | ||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 150 | $ | 250 | $ | 314 | $ | 714 | $ | 793 | ||||||||||||||||||||||
| Average interest rate | 5.0 | % | 4.9 | % | 7.6 | % | 6.1 | % | ||||||||||||||||||||||||
| Variable rate | $ | 29 | $ | 29 | $ | 29 | ||||||||||||||||||||||||||
| Average interest rate | 0.3 | % | 0.3 | % | ||||||||||||||||||||||||||||
| Short-term Borrowings: | $ | 124 | $ | 124 | $ | 124 | ||||||||||||||||||||||||||
| Average interest rate | 0.5 | % | 0.5 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy nuclear decommissioning obligations. Included in Met-Ed’s nuclear decommissioning trust are fixed income, equity securities and short-term investments carried at a market value of approximately $298 million as of December 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $16 million reduction in fair value as of December 31, 2010. The decommissioning trust of Med-Ed is subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. A decline in the value of the nuclear decommissioning trust or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During 2010, $3 million was contributed to the Met-Ed’s nuclear decommissioning trust to comply with regulatory requirements. Met-Ed continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
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PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also procures generation services for those customers electing to retain Penelec as their power supplier. Penelec purchased its POLR and default service requirements from FES through a fixed-price wholesale power sales agreement in 2010. Beginning in 2011, Penelec procures power under its Default Service Plan in which full requirements products (energy, capacity, ancillary services, applicable Transmission Services) are procured through descending clock auctions.
For additional information with respect to Penelec, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Strategy and Outlook, Risks and Challenges, Postretirement Benefits, Supply Plan, Capital Resources and Liquidity, Contractual Obligations, Regulatory Matters, Environmental Matters, Other Legal Proceedings, Critical Accounting Policies and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased by $6 million in 2010 compared to 2009. The decrease was primarily due to higher purchased power costs, other operating costs and interest expense, partially offset by higher revenues and net deferral of regulatory assets.
Revenues
Revenues increased by $91 million, or 6%, in 2010 compared to 2009. The increase in revenue was primarily due to higher generation revenues, partially offset by lower distribution and transmission revenues.
Distribution revenues increased by $1 million in 2010, compared to 2009, primarily due to an increase in the universal service and energy efficiency rates for the residential customer class and increased KWH sales in all customer classes, partially offset by a decrease in the CTC rate in all customer classes.
Changes in distribution KWH deliveries and revenues in 2010, compared to 2009, are summarized in the following tables:
| Distribution KWH Deliveries | Increase | |||
| Residential | 3.9 | % | ||
| Commercial | 3.5 | % | ||
| Industrial | 4.8 | % | ||
Increase in Distribution Deliveries | 4.0 | % | ||
| Increase | ||||
| Distribution Revenues | (Decrease) | |||
| (In millions) | ||||
| Residential | $ | 28 | ||
| Commercial | (16 | ) | ||
| Industrial | (11 | ) | ||
Net Increase in Distribution Revenues | $ | 1 | ||
Retail generation revenues increased $80 million in 2010, compared to 2009, primarily due to higher unit prices and higher KWH sales in all customer classes. The higher unit prices were primarily due to an increase in the generation rate, effective January 1, 2010. Higher KWH sales to industrial customers were due to improved economic conditions in Penelec’s service territory. Higher KWH sales to residential and commercial customers resulted primarily from weather-related usage, reflecting a 94% increase in cooling degree days in 2010, partially offset by a 4% decrease in heating degree days for the same period.
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Changes in retail generation KWH sales and revenues in 2010, compared to 2009, are summarized in the following tables:
| Retail Generation KWH Sales | Increase | |||
| Residential | 3.9 | % | ||
| Commercial | 2.7 | % | ||
| Industrial | 5.6 | % | ||
Increase in Retail Generation Sales | 3.9 | % | ||
| Retail Generation Revenues | Increase | |||
| (In millions) | ||||
| Residential | $ | 22 | ||
| Commercial | 30 | |||
| Industrial | 28 | |||
Increase in Retail Generation Revenues | $ | 80 | ||
Wholesale generation revenues increased $33 million in 2010 compared to 2009, due primarily to higher PJM capacity prices.
Transmission revenues decreased by $17 million in 2010 compared to 2009, primarily due to lower Financial Transmission Rights revenue. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses increased $89 million in 2010 compared to 2009. The following table presents changes from the prior year by expense category:
| Increase | ||||
| Expenses - Changes | (Decrease) | |||
| (In millions) | ||||
| Purchased power costs | $ | 121 | ||
| Other operating costs | 60 | |||
| Amortization (deferral) of regulatory assets, net | (91 | ) | ||
| General taxes | (1 | ) | ||
Net Increase in Expenses | $ | 89 | ||
Purchased power costs increased $121 million in 2010 compared to 2009, primarily due to an increase in unit costs and increased volumes purchased to source increased generation sales requirements. Other operating costs increased $60 million in 2010, primarily due to higher transmission congestion and transmission loss expenses (see reference to deferral accounting above). The amortization (deferral) of net regulatory assets decreased $91 million in 2010, primarily due to increased cost deferrals resulting from higher transmission expenses and decreased amortization of regulatory assets resulting from lower CTC revenues. General taxes decreased $1 million primarily due to a favorable ruling on a property tax appeal in the first quarter of 2010.
Other Expense
In 2010, other expense increased $15 million primarily due to an increase in interest expense on long-term debt as a result of a $500 million debt issuance in September 2009.
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Market Risk Information
Penelec uses various market risk sensitive instruments, including derivative contracts, to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight to risk management activities.
Commodity Price Risk
Penelec is exposed to market risk primarily due to fluctuations in electricity, energy transmission and natural gas prices. To manage the volatility relating to these exposures, Penelec uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes.
The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, Penelec relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. Penelec uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making. Sources of information for the valuation of commodity derivative contracts as of December 31, 2010 are summarized by contract year in the following table:
| Source of Information- | ||||||||||||||||||||||||||||
| Fair Value by Contract Year | 2011 | 2012 | 2013 | 2014 | 2015 | Thereafter | Total | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Prices actively quoted(1) | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||
Other external sources(2) | (69 | ) | (68 | ) | (10 | ) | (7 | ) | — | — | (154 | ) | ||||||||||||||||
| Prices based on models | — | — | — | — | 11 | 33 | 44 | |||||||||||||||||||||
Total(3) | $ | (69 | ) | $ | (68 | ) | $ | (10 | ) | $ | (7 | ) | $ | 11 | $ | 33 | $ | (110 | ) | |||||||||
| (1) | Represents futures and options traded on the New York Mercantile Exchange. | |
| (2) | Primarily represents contracts based on broker and IntercontinentalExchange quotes. | |
| (3) | Includes $110 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are subject to regulatory accounting and do not impact earnings. |
Penelec performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift in quoted market prices in the near term on derivative instruments would not have had a material effect on Penelec’s consolidated financial position or cash flows as of December 31, 2010. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would not have a material effect on Penelec’s net income for the next 12 months.
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Interest Rate Risk
Penelec’s exposure to fluctuations in market interest rates is reduced since a significant portion of its debt has fixed interest rates. The table below presents principal amounts and related weighted average interest rates by year of maturity for Penelec’s investment portfolio and debt obligations.
Comparison of Carrying Value to Fair Value
| There- | Fair | |||||||||||||||||||||||||||||||
| Year of Maturity | 2011 | 2012 | 2013 | 2014 | 2015 | after | Total | Value | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||
| Investments Other Than Cash and Cash Equivalents: | ||||||||||||||||||||||||||||||||
| Fixed Income | $ | 149 | $ | 149 | $ | 149 | ||||||||||||||||||||||||||
| Average interest rate | 1.7 | % | 1.7 | % | ||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||
| Long-term Debt: | ||||||||||||||||||||||||||||||||
| Fixed rate | $ | 150 | $ | 950 | $ | 1,100 | $ | 1,169 | ||||||||||||||||||||||||
| Average interest rate | 5.1 | % | 5.8 | % | 5.7 | % | ||||||||||||||||||||||||||
| Variable rate | $ | 20 | $ | 20 | $ | 20 | ||||||||||||||||||||||||||
| Average interest rate | 0.3 | % | 0.3 | % | ||||||||||||||||||||||||||||
| Short-term Borrowings: | $ | 101 | $ | 101 | $ | 101 | ||||||||||||||||||||||||||
| Average interest rate | 0.5 | % | 0.5 | % | ||||||||||||||||||||||||||||
Equity Price Risk
Nuclear decommissioning trust funds have been established to satisfy nuclear decommissioning obligations. Included in Penelec’s nuclear decommissioning trust are fixed income, equity securities and short-term investments carried at a market value of approximately $156 million as of December 31, 2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in an $8 million reduction in fair value as of December 31, 2010. The decommissioning trust of Penelec’s is subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. A decline in the value of the nuclear decommissioning trust or a significant escalation in estimated decommissioning costs could result in additional funding requirements. Penelec continues to evaluate the status of its funding obligations for the decommissioning of nuclear facilities.
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| ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
The information required by ITEM 7A relating to market risk is set forth in ITEM 7. Management Discussion and Analysis of Financial Condition and Results of Operations.
| ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA |
MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
The Company’s internal auditors, who are responsible to the Audit Committee of the Company’s Board of Directors, review the results and performance of operating units within the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
The Company’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.The effectiveness of the Company’s internal control over financial reporting, as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears on page 134.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of FirstEnergy Solutions Corp. (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Ohio Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of The Cleveland Electric Illuminating Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of The Toledo Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Jersey Central Power & Light Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Metropolitan Edison Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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MANAGEMENT REPORTS
Management’s Responsibility for Financial Statements
The consolidated financial statements of Pennsylvania Electric Company (Company) were prepared by management, who takes responsibility for their integrity and objectivity. The statements were prepared in conformity with accounting principles generally accepted in the United States and are consistent with other financial information appearing elsewhere in this report. PricewaterhouseCoopers LLP, an independent registered public accounting firm, has expressed an unqualified opinion on the Company’s 2010 consolidated financial statements.
FirstEnergy Corp.’s internal auditors, who are responsible to the Audit Committee of FirstEnergy’s Board of Directors, review the results and performance of the Company for adequacy, effectiveness and reliability of accounting and reporting systems, as well as managerial and operating controls.
FirstEnergy’s Audit Committee consists of four independent directors whose duties include: consideration of the adequacy of the internal controls of the Company and the objectivity of financial reporting; inquiry into the number, extent, adequacy and validity of regular and special audits conducted by independent auditors and the internal auditors; and reporting to the Board of Directors the Committee’s findings and any recommendation for changes in scope, methods or procedures of the auditing functions. The Committee is directly responsible for appointing the Company’s independent registered public accounting firm and is charged with reviewing and approving all services performed for the Company by the independent registered public accounting firm and for reviewing and approving the related fees. The Committee reviews the independent registered public accounting firm’s report on internal quality control and reviews all relationships between the independent registered public accounting firm and the Company, in order to assess the independent registered public accounting firm’s independence. The Committee also reviews management’s programs to monitor compliance with the Company’s policies on business ethics and risk management. The Committee establishes procedures to receive and respond to complaints received by the Company regarding accounting, internal accounting controls, or auditing matters and allows for the confidential, anonymous submission of concerns by employees. The Audit Committee held nine meetings in 2010.
Management’s Report on Internal Control Over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission inInternal Control — Integrated Framework, management conducted an evaluation of the effectiveness of the Company’s internal control over financial reporting under the supervision of the chief executive officer and the chief financial officer. Based on that evaluation, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2010.
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Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of FirstEnergy Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, common stockholders’ equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Corp. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
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Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of FirstEnergy Solutions Corp.:
Directors of FirstEnergy Solutions Corp.:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of FirstEnergy Solutions Corp. and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
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Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Ohio Edison Company:
Directors of Ohio Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Ohio Edison Company and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
134
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Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of
The Cleveland Electric Illuminating Company:
The Cleveland Electric Illuminating Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Cleveland Electric Illuminating Company and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
135
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of The Toledo Edison Company:
Directors of The Toledo Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of The Toledo Edison Company and its subsidiary at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
136
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of
Jersey Central Power & Light Company:
Jersey Central Power & Light Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Jersey Central Power & Light Company and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
137
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Metropolitan Edison Company:
Directors of Metropolitan Edison Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Metropolitan Edison Company and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
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Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of
Directors of Pennsylvania Electric Company:
Directors of Pennsylvania Electric Company:
In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, capitalization, common stockholder’s equity, and cash flows present fairly, in all material respects, the financial position of Pennsylvania Electric Company and its subsidiaries at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Cleveland, Ohio
February 16, 2011
Cleveland, Ohio
February 16, 2011
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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In millions, except per share amounts) | 2010 | 2009 | 2008 | |||||||||
REVENUES: | ||||||||||||
| Electric utilities | $ | 9,815 | $ | 11,139 | $ | 12,061 | ||||||
| Unregulated businesses | 3,524 | 1,834 | 1,566 | |||||||||
| Total revenues* | 13,339 | 12,973 | 13,627 | |||||||||
EXPENSES: | ||||||||||||
| Fuel | 1,432 | 1,153 | 1,340 | |||||||||
| Purchased power | 4,624 | 4,730 | 4,291 | |||||||||
| Other operating expenses | 2,850 | 2,697 | 3,045 | |||||||||
| Provision for depreciation | 746 | 736 | 677 | |||||||||
| Amortization of regulatory assets | 722 | 1,155 | 1,053 | |||||||||
| Deferral of regulatory assets | — | (136 | ) | (316 | ) | |||||||
| General taxes | 776 | 753 | 778 | |||||||||
| Impairment of long-lived assets | 384 | 6 | — | |||||||||
| Total expenses | 11,534 | 11,094 | 10,868 | |||||||||
OPERATING INCOME | 1,805 | 1,879 | 2,759 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
| Investment income | 117 | 204 | 59 | |||||||||
| Interest expense | (845 | ) | (978 | ) | (754 | ) | ||||||
| Capitalized interest | 165 | 130 | 52 | |||||||||
| Total other expense | (563 | ) | (644 | ) | (643 | ) | ||||||
INCOME BEFORE INCOME TAXES | 1,242 | 1,235 | 2,116 | |||||||||
INCOME TAXES | 482 | 245 | 777 | |||||||||
NET INCOME | 760 | 990 | 1,339 | |||||||||
| Loss attributable to noncontrolling interest | (24 | ) | (16 | ) | (3 | ) | ||||||
EARNINGS AVAILABLE TO FIRSTENERGY CORP. | $ | 784 | $ | 1,006 | $ | 1,342 | ||||||
BASIC EARNINGS PER SHARE OF COMMON STOCK | $ | 2.58 | $ | 3.31 | $ | 4.41 | ||||||
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | 304 | 304 | 304 | |||||||||
DILUTED EARNINGS PER SHARE OF COMMON STOCK | $ | 2.57 | $ | 3.29 | $ | 4.38 | ||||||
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | 305 | 306 | 307 | |||||||||
| * | Includes $428 million, $395 million and $432 million of excise tax collections in 2010, 2009 and 2008, respectively. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in millions) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 1,019 | $ | 874 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $36 in 2010 and $33 in 2009 | 1,392 | 1,244 | ||||||
| Other, net of allowance for uncollectible accounts of $8 in 2010 and $7 in 2009 | 176 | 153 | ||||||
| Materials and supplies, at average cost | 638 | 647 | ||||||
| Prepaid taxes | 199 | 248 | ||||||
| Other | 274 | 154 | ||||||
| 3,698 | 3,320 | |||||||
PROPERTY, PLANT AND EQUIPMENT: | ||||||||
| In service | 29,451 | 27,826 | ||||||
| Less — Accumulated provision for depreciation | 11,180 | 11,397 | ||||||
| 18,271 | 16,429 | |||||||
| Construction work in progress | 1,517 | 2,735 | ||||||
| 19,788 | 19,164 | |||||||
INVESTMENTS: | ||||||||
| Nuclear plant decommissioning trusts | 1,973 | 1,859 | ||||||
| Investments in lease obligation bonds | 476 | 543 | ||||||
| Other | 553 | 621 | ||||||
| 3,002 | 3,023 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 5,575 | 5,575 | ||||||
| Regulatory assets | 1,826 | 2,356 | ||||||
| Power purchase contract asset | 122 | 200 | ||||||
| Other | 794 | 666 | ||||||
| 8,317 | 8,797 | |||||||
| $ | 34,805 | $ | 34,304 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 1,486 | $ | 1,834 | ||||
| Short-term borrowings | 700 | 1,081 | ||||||
| Accounts payable | 872 | 829 | ||||||
| Accrued taxes | 326 | 314 | ||||||
| Accrued compensation and benefits | 315 | 293 | ||||||
| Derivatives | 266 | 126 | ||||||
| Other | 733 | 711 | ||||||
| 4,698 | 5,188 | |||||||
CAPITALIZATION: | ||||||||
| Common stockholders’ equity- | ||||||||
| Common stock, $0.10 par value, authorized 375,000,000 shares- 304,835,407 shares outstanding | 31 | 31 | ||||||
| Other paid-in capital | 5,444 | 5,448 | ||||||
| Accumulated other comprehensive loss | (1,539 | ) | (1,415 | ) | ||||
| Retained earnings | 4,609 | 4,495 | ||||||
| Total common stockholders’ equity | 8,545 | 8,559 | ||||||
| Noncontrolling interest | (32 | ) | (2 | ) | ||||
| Total equity | 8,513 | 8,557 | ||||||
| Long-term debt and other long-term obligations | 12,579 | 12,008 | ||||||
| 21,092 | 20,565 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 2,879 | 2,468 | ||||||
| Retirement benefits | 1,868 | 1,534 | ||||||
| Asset retirement obligations | 1,407 | 1,425 | ||||||
| Deferred gain on sale and leaseback transaction | 959 | 993 | ||||||
| Power purchase contract liability | 466 | 643 | ||||||
| Lease market valuation liability | 217 | 262 | ||||||
| Other | 1,219 | 1,226 | ||||||
| 9,015 | 8,551 | |||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 7 and 14) | ||||||||
| $ | 34,805 | $ | 34,304 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY
| Accumulated | ||||||||||||||||||||||||
| Common Stock | Other | Other | ||||||||||||||||||||||
| Comprehensive | Number | Par | Paid-In | Comprehensive | Retained | |||||||||||||||||||
| (Dollars in millions) | Income | of Shares | Value | Capital | Income (Loss) | Earnings | ||||||||||||||||||
| Balance, January 1, 2008 | 304,835,407 | $ | 31 | $ | 5,509 | $ | (50 | ) | $ | 3,487 | ||||||||||||||
| Earnings available to FirstEnergy Corp. | $ | 1,342 | 1,342 | |||||||||||||||||||||
| Unrealized loss on derivative hedges, net of $16 million of income tax benefits | (28 | ) | (28 | ) | ||||||||||||||||||||
| Change in unrealized gain on investments, net of $86 million of income tax benefits | (146 | ) | (146 | ) | ||||||||||||||||||||
| Pension and other postretirement benefits, net of $697 million of income tax benefits (Note 3) | (1,156 | ) | (1,156 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 12 | ||||||||||||||||||||||
| Stock options exercised | (36 | ) | ||||||||||||||||||||||
| Restricted stock units | (1 | ) | ||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (670 | ) | ||||||||||||||||||||||
| Balance, December 31, 2008 | 304,835,407 | 31 | 5,473 | (1,380 | ) | 4,159 | ||||||||||||||||||
| Earnings available to FirstEnergy Corp. | $ | 1,006 | 1,006 | |||||||||||||||||||||
| Unrealized gain on derivative hedges, net of $24 million of income taxes | 27 | 27 | ||||||||||||||||||||||
| Change in unrealized gain on investments, net of $31 million of income tax benefits | (43 | ) | (43 | ) | ||||||||||||||||||||
| Pension and other postretirement benefits, net of $34 million of income taxes (Note 3) | (19 | ) | (19 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 971 | ||||||||||||||||||||||
| Stock options exercised | (3 | ) | ||||||||||||||||||||||
| Restricted stock units | 7 | |||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Acquisition adjustment of non-controlling interest (Note 8) | (30 | ) | ||||||||||||||||||||||
| Cash dividends declared on common stock | (670 | ) | ||||||||||||||||||||||
| Balance, December 31, 2009 | 304,835,407 | 31 | 5,448 | (1,415 | ) | 4,495 | ||||||||||||||||||
| Earnings available to FirstEnergy Corp. | $ | 784 | 784 | |||||||||||||||||||||
| Unrealized gain on derivative hedges, net of $14 million of income taxes | 22 | 22 | ||||||||||||||||||||||
| Unrealized gain on investments, net of $3 million of income taxes | 5 | 5 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $107 million of income tax benefits (Note 3) | (151 | ) | (151 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 660 | ||||||||||||||||||||||
| Stock options exercised | (2 | ) | ||||||||||||||||||||||
| Restricted stock units | (3 | ) | ||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (670 | ) | ||||||||||||||||||||||
| Balance, December 31, 2010 | 304,835,407 | $ | 31 | $ | 5,444 | $ | (1,539 | ) | $ | 4,609 | ||||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| As of December 31, | ||||||||||||
| (In millions) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 760 | $ | 990 | $ | 1,339 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 746 | 736 | 677 | |||||||||
| Amortization of regulatory assets | 722 | 1,155 | 1,053 | |||||||||
| Deferral of regulatory assets | — | (136 | ) | (316 | ) | |||||||
| Nuclear fuel and lease amortization | 168 | 128 | 112 | |||||||||
| Deferred purchased power and other costs | (254 | ) | (338 | ) | (226 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 470 | 384 | 366 | |||||||||
| Impairment of long-lived assets (Note 19) | 384 | 6 | — | |||||||||
| Investment impairment (Note 2(E)) | 33 | 62 | 123 | |||||||||
| Deferred rents and lease market valuation liability | (54 | ) | (52 | ) | (95 | ) | ||||||
| Stock based compensation | (1 | ) | 20 | (64 | ) | |||||||
| Accrued compensation and retirement benefits | 89 | 22 | (140 | ) | ||||||||
| Gain on asset sales | (2 | ) | (27 | ) | (72 | ) | ||||||
| Electric service prepayment programs | — | (10 | ) | (77 | ) | |||||||
| Cash collateral, net | (26 | ) | 30 | (31 | ) | |||||||
| Gain on sales of investment securities held in trusts, net | (55 | ) | (176 | ) | (63 | ) | ||||||
| Loss on debt redemption | 5 | 146 | — | |||||||||
| Interest rate swap transactions | 129 | — | — | |||||||||
| Commodity derivative transactions, net (Note 6) | (81 | ) | 229 | 5 | ||||||||
| Pension trust contributions | — | (500 | ) | — | ||||||||
| Uncertain tax positions | (34 | ) | (210 | ) | (5 | ) | ||||||
| Acquisition of supply requirements | — | (93 | ) | — | ||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | (177 | ) | 75 | (29 | ) | |||||||
| Materials and supplies | 2 | (11 | ) | (52 | ) | |||||||
| Prepayments and other current assets | 100 | (19 | ) | (263 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | 43 | 50 | 10 | |||||||||
| Accrued taxes | 57 | (103 | ) | (39 | ) | |||||||
| Accrued interest | 7 | 67 | 4 | |||||||||
| Other | 45 | 40 | 7 | |||||||||
| Net cash provided from operating activities | $ | 3,076 | $ | 2,465 | $ | 2,224 | ||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | 1,099 | 4,632 | 1,367 | |||||||||
| Short-term borrowings, net | — | — | 1,494 | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (1,015 | ) | (2,610 | ) | (1,034 | ) | ||||||
| Short-term borrowings, net | (378 | ) | (1,246 | ) | — | |||||||
| Common stock dividend payments | (670 | ) | (670 | ) | (671 | ) | ||||||
| Other | (19 | ) | (57 | ) | 19 | |||||||
| Net cash provided from (used for) financing activities | $ | (983 | ) | $ | 49 | $ | 1,175 | |||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (1,963 | ) | (2,203 | ) | (2,888 | ) | ||||||
| Proceeds from asset sales | 117 | 21 | 72 | |||||||||
| Sales of investment securities held in trusts | 3,172 | 2,229 | 1,656 | |||||||||
| Purchases of investment securities held in trusts | (3,219 | ) | (2,306 | ) | (1,749 | ) | ||||||
| Customer acquisition costs | (113 | ) | — | — | ||||||||
| Cash investments (Note 5) | 66 | 60 | 60 | |||||||||
| Other | (8 | ) | 14 | (134 | ) | |||||||
| Net cash used for investing activities | $ | (1,948 | ) | $ | (2,185 | ) | $ | (2,983 | ) | |||
| Net increase in cash and cash equivalents | 145 | 329 | 416 | |||||||||
| Cash and cash equivalents at beginning of year | 874 | 545 | 129 | |||||||||
| Cash and cash equivalents at end of year | $ | 1,019 | $ | 874 | $ | 545 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 662 | $ | 718 | $ | 667 | ||||||
| Income taxes (benefits) | $ | (42 | ) | $ | 173 | $ | 685 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES: | ||||||||||||
| Electric sales to affiliates (Note 17) | $ | 2,227,277 | $ | 2,825,959 | $ | 2,968,323 | ||||||
| Electric sales to non-affiliates | 3,251,765 | 1,447,482 | 1,332,364 | |||||||||
| Other | 348,572 | 454,896 | 217,666 | |||||||||
| Total revenues | 5,827,614 | 4,728,337 | 4,518,353 | |||||||||
EXPENSES: | ||||||||||||
| Fuel | 1,402,839 | 1,127,463 | 1,315,293 | |||||||||
| Purchased power from affiliates (Note 17) | 370,692 | 222,406 | 101,409 | |||||||||
| Purchased power from non-affiliates | 1,585,207 | 996,383 | 778,882 | |||||||||
| Other operating expenses | 1,279,340 | 1,183,225 | 1,084,548 | |||||||||
| Provision for depreciation | 243,296 | 259,393 | 231,899 | |||||||||
| General taxes | 93,777 | 86,915 | 88,004 | |||||||||
| Impairment of long-lived assets | 383,665 | 6,067 | — | |||||||||
| Total expenses | 5,358,816 | 3,881,852 | 3,600,035 | |||||||||
OPERATING INCOME | 468,798 | 846,485 | 918,318 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
| Investment income | 59,202 | 125,226 | (22,678 | ) | ||||||||
| Miscellaneous income | 16,667 | 12,737 | 1,698 | |||||||||
| Interest expense — affiliates | (9,755 | ) | (10,106 | ) | (29,829 | ) | ||||||
| Interest expense — other | (206,100 | ) | (142,120 | ) | (111,682 | ) | ||||||
| Capitalized interest | 91,673 | 60,152 | 43,764 | |||||||||
| Total other income (expense) | (48,313 | ) | 45,889 | (118,727 | ) | |||||||
INCOME BEFORE INCOME TAXES | 420,485 | 892,374 | 799,591 | |||||||||
INCOME TAXES | 151,057 | 315,290 | 293,181 | |||||||||
NET INCOME | $ | 269,428 | $ | 577,084 | $ | 506,410 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 9,281 | $ | 12 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $16,591 in 2010 and $12,041 in 2009 | 365,758 | 195,107 | ||||||
| Associated companies | 477,565 | 318,561 | ||||||
| Other, net of allowance for uncollectible accounts of $6,765 in 2010 and $6,702 in 2009 | 89,550 | 51,872 | ||||||
| Notes receivable from associated companies | 396,770 | 805,103 | ||||||
| Materials and supplies, at average cost | 545,342 | 539,541 | ||||||
| Derivatives | 181,660 | 31,485 | ||||||
| Prepayments and other | 60,171 | 76,297 | ||||||
| 2,126,097 | 2,017,978 | |||||||
PROPERTY, PLANT AND EQUIPMENT: | ||||||||
| In service | 11,321,318 | 10,357,632 | ||||||
| Less — Accumulated provision for depreciation | 4,024,280 | 4,531,158 | ||||||
| 7,297,038 | 5,826,474 | |||||||
| Construction work in progress | 1,062,744 | 2,423,446 | ||||||
| 8,359,782 | 8,249,920 | |||||||
INVESTMENTS: | ||||||||
| Nuclear plant decommissioning trusts | 1,145,846 | 1,088,641 | ||||||
| Other | 11,704 | 22,466 | ||||||
| 1,157,550 | 1,111,107 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Accumulated deferred income tax benefits | — | 86,626 | ||||||
| Customer intangibles | 133,968 | 16,566 | ||||||
| Goodwill | 24,248 | 24,248 | ||||||
| Property taxes | 41,112 | 50,125 | ||||||
| Unamortized sale and leaseback costs | 73,386 | 72,553 | ||||||
| Derivatives | 97,603 | 28,368 | ||||||
| Other | 48,689 | 93,297 | ||||||
| 419,006 | 371,783 | |||||||
| $ | 12,062,435 | $ | 11,750,788 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 1,132,135 | $ | 1,550,927 | ||||
| Short-term borrowings- | ||||||||
| Associated companies | 11,561 | 9,237 | ||||||
| Accounts payable- | ||||||||
| Associated companies | 466,623 | 466,078 | ||||||
| Other | 241,191 | 245,363 | ||||||
| Accrued taxes | 70,129 | 83,158 | ||||||
| Derivatives | 266,411 | 125,609 | ||||||
| Other | 251,671 | 233,448 | ||||||
| 2,439,721 | 2,713,820 | |||||||
CAPITALIZATION: | ||||||||
| Total common stockholder’s equity | 3,788,245 | 3,514,571 | ||||||
| Noncontrolling interest | (504 | ) | — | |||||
| Total equity | 3,787,741 | 3,514,571 | ||||||
| Long-term debt and other long-term obligations | 3,180,875 | 2,811,652 | ||||||
| 6,968,616 | 6,326,223 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Deferred gain on sale and leaseback transaction | 959,154 | 992,869 | ||||||
| Accumulated deferred income taxes | 57,595 | — | ||||||
| Accumulated deferred investment tax credits | 54,224 | 58,396 | ||||||
| Asset retirement obligations | 892,051 | 921,448 | ||||||
| Retirement benefits | 285,160 | 204,035 | ||||||
| Property taxes | 41,112 | 50,125 | ||||||
| Lease market valuation liability | 216,695 | 262,200 | ||||||
| Other | 148,107 | 221,672 | ||||||
| 2,654,098 | 2,710,745 | |||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 7 & 14) | ||||||||
| $ | 12,062,435 | $ | 11,750,788 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, without par value, authorized 750 shares, 7 shares outstanding | $ | 1,490,082 | $ | 1,468,423 | ||||
| Accumulated other comprehensive loss (Note 2(F)) | (120,414 | ) | (103,001 | ) | ||||
| Retained earnings (Note 11(A)) | 2,418,577 | 2,149,149 | ||||||
| Total | 3,788,245 | 3,514,571 | ||||||
NONCONTROLLING INTEREST | (504 | ) | — | |||||
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)): | ||||||||
Secured notes: | ||||||||
FirstEnergy Solutions Corp. | ||||||||
| 5.150% due 2010-2015 | 21,146 | 21,950 | ||||||
| *2.000% due 2011 | 100,000 | 100,000 | ||||||
| 121,146 | 121,950 | |||||||
FirstEnergy Generation Corp. | ||||||||
| 5.700% due 2014 | 50,000 | 50,000 | ||||||
| *0.310% due 2017 | 28,525 | 28,525 | ||||||
| 5.630% due 2018 | 141,260 | 141,260 | ||||||
| *0.290% due 2019 | 90,140 | 90,140 | ||||||
| 5.250% due 2023 | 50,000 | 50,000 | ||||||
| 4.750% due 2029 | 100,000 | 100,000 | ||||||
| 4.750% due 2029 | 6,450 | 6,450 | ||||||
| *0.300% due 2041 | 56,600 | 56,600 | ||||||
| 522,975 | 522,975 | |||||||
FirstEnergy Nuclear Generation Corp. | ||||||||
| 8.830% due 2010-2016 | 3,921 | 4,514 | ||||||
| 8.890% due 2010-2016 | 68,728 | 77,445 | ||||||
| 9.000% due 2010-2017 | 171,924 | 206,453 | ||||||
| 9.120% due 2010-2016 | 53,506 | 61,455 | ||||||
| 12.000% due 2010-2017 | 962 | 1,072 | ||||||
| *0.320% due 2035 | 60,000 | 60,000 | ||||||
| *0.330% due 2035 | 98,900 | 98,900 | ||||||
| 5.750% due 2033 | 62,500 | 62,500 | ||||||
| 5.875% due 2033 | 107,500 | 107,500 | ||||||
| 627,941 | 679,839 | |||||||
| Total secured notes | 1,272,062 | 1,324,764 | ||||||
Unsecured notes: | ||||||||
FirstEnergy Solutions Corp. | ||||||||
| 4.800% due 2015 | 400,000 | 400,000 | ||||||
| 6.050% due 2021 | 600,000 | 600,000 | ||||||
| 6.800% due 2039 | 500,000 | 500,000 | ||||||
| 1,500,000 | 1,500,000 | |||||||
FirstEnergy Generation Corp. | ||||||||
| 7.000% due 2011 | 4,678 | — | ||||||
| 0.000% due 2016 | 2,632 | — | ||||||
| 3.000% due 2018 | 2,805 | 2,805 | ||||||
| 3.000% due 2018 | 2,985 | 2,985 | ||||||
| 5.700% due 2020 | 177,000 | 177,000 | ||||||
| **2.250% due 2023 | 234,520 | 234,520 | ||||||
| **1.500% due 2028 | 15,000 | 15,000 | ||||||
| 7.125% due 2028 | 25,000 | 25,000 | ||||||
| **3.375% due 2040 | 43,000 | 43,000 | ||||||
| *0.320% due 2041 | 129,610 | 129,610 | ||||||
| **3.000% due 2041 | 26,000 | 26,000 | ||||||
| 3.000% due 2047 | 46,300 | 46,300 | ||||||
| 709,530 | 702,220 | |||||||
FirstEnergy Nuclear Generation Corp. | ||||||||
| 7.250% due 2032 | 23,000 | 23,000 | ||||||
| 7.250% due 2032 | 33,000 | 33,000 | ||||||
| **2.250% due 2033 | 46,500 | 46,500 | ||||||
| **2.750% due 2033 | 54,600 | 54,600 | ||||||
| **3.750% due 2033 | 26,000 | 26,000 | ||||||
| **3.375% due 2033 | 99,100 | 99,100 | ||||||
| **3.375% due 2033 | 8,000 | 8,000 | ||||||
| *0.280% due 2033 | 135,550 | 135,550 | ||||||
| *0.330% due 2033 | 15,500 | 15,500 | ||||||
| 3.000% due 2033 | 20,450 | 20,450 | ||||||
| 3.000% due 2033 | 9,100 | 9,100 | ||||||
| **3.375% due 2034 | 7,200 | 7,200 | ||||||
| **3.375% due 2034 | 82,800 | 82,800 | ||||||
| **3.375% due 2035 | 72,650 | 72,650 | ||||||
| *0.290% due 2035 | 163,965 | 163,965 | ||||||
| 797,415 | 797,415 | |||||||
| Total unsecured notes | 3,006,945 | 2,999,635 | ||||||
| Capital lease obligations (Note 7) | 35,788 | 40,110 | ||||||
| Net unamortized discount on debt | (1,785 | ) | (1,930 | ) | ||||
| Long-term debt due within one year | (1,132,135 | ) | (1,550,927 | ) | ||||
| Total long-term debt and other long-term obligations | 3,180,875 | 2,811,652 | ||||||
TOTAL CAPITALIZATION | $ | 6,968,616 | $ | 6,326,223 | ||||
| * | Denotes variable rate issue with applicable year-end interest rate shown. | |
| ** | Denotes remarketed unsecured notes in 2010. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||
| Common Stock | Other | |||||||||||||||||||
| Comprehensive | Number | Carrying | Comprehensive | Retained | ||||||||||||||||
| (Dollars in thousands) | Income | of Shares | Value | Income (Loss) | Earnings | |||||||||||||||
| Balance, January 1, 2008 | 7 | $ | 1,164,922 | $ | 140,654 | $ | 1,108,655 | |||||||||||||
| Net income | $ | 506,410 | 506,410 | |||||||||||||||||
| Net unrealized loss on derivative instruments, net of $5,512 of income tax benefits | (9,200 | ) | (9,200 | ) | ||||||||||||||||
| Change in unrealized gain on investments, net of $82,014 of income tax benefits | (137,689 | ) | (137,689 | ) | ||||||||||||||||
| Pension and other postretirement benefits, net of $47,853 of income tax benefits (Note 3) | (85,636 | ) | (85,636 | ) | ||||||||||||||||
| Comprehensive income | $ | 273,885 | ||||||||||||||||||
| Equity contribution from parent | 280,000 | |||||||||||||||||||
| Stock options exercised, restricted stock units and other adjustments | 13,262 | |||||||||||||||||||
| Consolidated tax benefit allocation | 6,045 | |||||||||||||||||||
| Cash dividends declared on common stock | (43,000 | ) | ||||||||||||||||||
| Balance, December 31, 2008 | 7 | 1,464,229 | (91,871 | ) | 1,572,065 | |||||||||||||||
| Net income | $ | 577,084 | 577,084 | |||||||||||||||||
| Net unrealized gain on derivative instruments, net of $6,766 of income taxes | 11,329 | 11,329 | ||||||||||||||||||
| Change in unrealized gain on investments, net of $20,937 of income tax benefits | (28,306 | ) | (28,306 | ) | ||||||||||||||||
| Pension and other postretirement benefits, net of $8,472 of income taxes (Note 3) | 5,847 | 5,847 | ||||||||||||||||||
| Comprehensive income | $ | 565,954 | ||||||||||||||||||
| Restricted stock units | 866 | |||||||||||||||||||
| Consolidated tax benefit allocation | 3,328 | |||||||||||||||||||
| Balance, December 31, 2009 | 7 | 1,468,423 | (103,001 | ) | 2,149,149 | |||||||||||||||
| Net income | 269,428 | 269,428 | ||||||||||||||||||
| Net unrealized gain on derivative instruments, net of $8,835 of income taxes | 14,363 | 14,363 | ||||||||||||||||||
| Change in unrealized gain on investments, net of $2,846 of income taxes | 4,765 | 4,765 | ||||||||||||||||||
| Pension and other postretirement benefits, net of $22,369 of income tax benefits (Note 3) | (36,541 | ) | (36,541 | ) | ||||||||||||||||
| Comprehensive income | $ | 252,015 | ||||||||||||||||||
| Restricted stock units | (329 | ) | ||||||||||||||||||
| Consolidated tax benefit allocation | 21,988 | |||||||||||||||||||
| Balance, December 31, 2010 | 7 | $ | 1,490,082 | $ | (120,414 | ) | $ | 2,418,577 | ||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net Income | $ | 269,428 | $ | 577,084 | $ | 506,410 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 243,296 | 259,393 | 231,899 | |||||||||
| Nuclear fuel and lease amortization | 172,132 | 130,486 | 111,978 | |||||||||
| Deferred rents and lease market valuation liability | (47,319 | ) | (46,384 | ) | (43,263 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 175,653 | 219,962 | 116,626 | |||||||||
| Impairment of long-lived assets (Note 19) | 383,665 | 6,067 | — | |||||||||
| Investment impairments (Note 2(E)) | 32,254 | 57,073 | 115,207 | |||||||||
| Accrued compensation and retirement benefits | 24,973 | 6,162 | 16,011 | |||||||||
| Commodity derivative transactions, net (Note 6) | (81,362 | ) | 228,705 | 5,100 | ||||||||
| Gain on asset sales | (2,333 | ) | (10,649 | ) | (38,858 | ) | ||||||
| Gain on investment securities held in trusts, net | (50,693 | ) | (158,112 | ) | (53,290 | ) | ||||||
| Acquisition of supply requirements | — | (93,371 | ) | — | ||||||||
| Cash collateral, net | (6,581 | ) | 20,208 | (60,621 | ) | |||||||
| Associated company lease assignment | — | 71,356 | — | |||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | (361,901 | ) | (34,429 | ) | 59,782 | |||||||
| Materials and supplies | (11,015 | ) | 12,513 | (59,983 | ) | |||||||
| Prepayments and other current assets | 41,937 | (26,046 | ) | (12,302 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (27,457 | ) | 67,855 | 34,467 | ||||||||
| Accrued taxes | 2,303 | 6,059 | (90,568 | ) | ||||||||
| Accrued interest | (1,873 | ) | 46,441 | 1,398 | ||||||||
| Other | 31,015 | 33,916 | 12,935 | |||||||||
| Net cash provided from operating activities | 786,122 | 1,374,289 | 852,928 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | 715,370 | 2,438,402 | 618,375 | |||||||||
| Equity contributions from parent | — | — | 280,000 | |||||||||
| Short-term borrowings, net | 2,324 | — | 700,759 | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (772,454 | ) | (709,156 | ) | (462,540 | ) | ||||||
| Short-term borrowings, net | — | (1,155,586 | ) | — | ||||||||
| Common stock dividend payments | — | — | (43,000 | ) | ||||||||
| Other | (2,140 | ) | (21,790 | ) | (5,147 | ) | ||||||
| Net cash provided from (used for) financing activities | (56,900 | ) | 551,870 | 1,088,447 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (1,034,685 | ) | (1,222,933 | ) | (1,835,629 | ) | ||||||
| Proceeds from asset sales | 117,333 | 18,371 | 23,077 | |||||||||
| Sales of investment securities held in trusts | 1,926,684 | 1,379,154 | 950,688 | |||||||||
| Purchases of investment securities held in trusts | (1,974,020 | ) | (1,405,996 | ) | (987,304 | ) | ||||||
| Loans from (to) associated companies, net | 408,333 | (675,928 | ) | (36,391 | ) | |||||||
| Customer acquisition costs | (113,336 | ) | — | — | ||||||||
| Leasehold improvement payments to associated companies | (51,204 | ) | — | — | ||||||||
| Other | 942 | (18,854 | ) | (55,779 | ) | |||||||
| Net cash used for investing activities | (719,953 | ) | (1,926,186 | ) | (1,941,338 | ) | ||||||
| Net change in cash and cash equivalents | 9,269 | (27 | ) | 37 | ||||||||
| Cash and cash equivalents at beginning of period | 12 | 39 | 2 | |||||||||
| Cash and cash equivalents at end of period | $ | 9,281 | $ | 12 | $ | 39 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 116,713 | $ | 38,446 | $ | 92,103 | ||||||
| Income taxes | $ | 139,953 | $ | 96,045 | $ | 196,963 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES (Note 17): | ||||||||||||
| Electric sales | $ | 1,729,367 | $ | 2,418,292 | $ | 2,487,956 | ||||||
| Excise and gross receipts tax collections | 106,751 | 98,630 | 113,805 | |||||||||
| Total revenues | 1,836,118 | 2,516,922 | 2,601,761 | |||||||||
EXPENSES (Note 17): | ||||||||||||
| Purchased power from affiliates | 521,052 | 991,405 | 1,203,314 | |||||||||
| Purchased power from non-affiliates | 316,712 | 481,406 | 114,972 | |||||||||
| Other operating costs | 364,274 | 461,142 | 565,893 | |||||||||
| Provision for depreciation | 88,154 | 89,289 | 79,444 | |||||||||
| Amortization of regulatory assets, net | 62,857 | 93,694 | 117,733 | |||||||||
| General taxes | 182,679 | 171,082 | 186,396 | |||||||||
| Total expenses | 1,535,728 | 2,288,018 | 2,267,752 | |||||||||
OPERATING INCOME | 300,390 | 228,904 | 334,009 | |||||||||
OTHER INCOME (EXPENSE) (Note 17): | ||||||||||||
| Investment income | 21,758 | 46,887 | 56,103 | |||||||||
| Miscellaneous income (expense) | 4,455 | 2,654 | (4,525 | ) | ||||||||
| Interest expense | (88,588 | ) | (90,669 | ) | (75,058 | ) | ||||||
| Capitalized interest | 1,197 | 844 | 414 | |||||||||
| Total other expense | (61,178 | ) | (40,284 | ) | (23,066 | ) | ||||||
INCOME BEFORE INCOME TAXES | 239,212 | 188,620 | 310,943 | |||||||||
INCOME TAXES | 81,972 | 66,186 | 98,584 | |||||||||
NET INCOME | 157,240 | 122,434 | 212,359 | |||||||||
| Income from noncontrolling interest | 509 | 567 | 613 | |||||||||
EARNINGS AVAILABLE TO PARENT | $ | 156,731 | $ | 121,867 | $ | 211,746 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 420,489 | $ | 324,175 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $4,086 in 2010 and $5,119 in 2009 | 176,591 | 209,384 | ||||||
| Associated companies | 118,135 | 98,874 | ||||||
| Other | 12,232 | 14,155 | ||||||
| Notes receivable from associated companies | 16,957 | 118,651 | ||||||
| Prepayments and other | 6,393 | 15,964 | ||||||
| 750,797 | 781,203 | |||||||
UTILITY PLANT: | ||||||||
| In service | 3,136,623 | 3,036,467 | ||||||
| Less — Accumulated provision for depreciation | 1,207,745 | 1,165,394 | ||||||
| 1,928,878 | 1,871,073 | |||||||
| Construction work in progress | 45,103 | 31,171 | ||||||
| 1,973,981 | 1,902,244 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Investment in lease obligation bonds (Note 7) | 190,420 | 216,600 | ||||||
| Nuclear plant decommissioning trusts | 127,017 | 120,812 | ||||||
| Other | 95,563 | 96,861 | ||||||
| 413,000 | 434,273 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Regulatory assets | 400,322 | 465,331 | ||||||
| Pension assets (Note 3) | 28,596 | 19,881 | ||||||
| Property taxes | 71,331 | 67,037 | ||||||
| Unamortized sale and leaseback costs | 30,126 | 35,127 | ||||||
| Other | 17,634 | 39,881 | ||||||
| 548,009 | 627,257 | |||||||
| $ | 3,685,787 | $ | 3,744,977 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 1,419 | $ | 2,723 | ||||
| Short-term borrowings- | ||||||||
| Associated companies | 142,116 | 92,863 | ||||||
| Other | 320 | 807 | ||||||
| Accounts payable- | ||||||||
| Associated companies | 99,421 | 102,763 | ||||||
| Other | 29,639 | 40,423 | ||||||
| Accrued taxes | 78,707 | 81,868 | ||||||
| Accrued interest | 25,382 | 25,749 | ||||||
| Other | 74,947 | 81,424 | ||||||
| 451,951 | 428,620 | |||||||
CAPITALIZATION (See Consolidated Statements of Capitalization): | ||||||||
| Common stockholder’s equity | 914,411 | 1,021,110 | ||||||
| Noncontrolling interest | 5,680 | 6,442 | ||||||
| Total equity | 920,091 | 1,027,552 | ||||||
| Long-term debt and other long-term obligations | 1,152,134 | 1,160,208 | ||||||
| 2,072,225 | 2,187,760 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 696,410 | 660,114 | ||||||
| Accumulated deferred investment tax credits | 10,159 | 11,406 | ||||||
| Retirement benefits | 183,712 | 174,925 | ||||||
| Asset retirement obligations | 74,456 | 85,926 | ||||||
| Other | 196,874 | 196,226 | ||||||
| 1,161,611 | 1,128,597 | |||||||
COMMITMENTS AND CONTINGENCIES (Notes 7 and 14) | ||||||||
| $ | 3,685,787 | $ | 3,744,977 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, without par value, 175,000,000 shares authorized, 60 shares outstanding | $ | 951,866 | $ | 1,154,797 | ||||
| Accumulated other comprehensive loss (Note 2(F)) | (179,076 | ) | (163,577 | ) | ||||
| Retained earnings (Note 11(A)) | 141,621 | 29,890 | ||||||
| Total | 914,411 | 1,021,110 | ||||||
NONCONTROLLING INTEREST | 5,680 | 6,442 | ||||||
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)): | ||||||||
Ohio Edison Company- | ||||||||
First mortgage bonds: | ||||||||
| 8.250% due 2018 | 25,000 | 25,000 | ||||||
| 8.250% due 2038 | 275,000 | 275,000 | ||||||
| Total | 300,000 | 300,000 | ||||||
Secured notes: | ||||||||
| 7.156% weighted average interest rate due 2009-2010 | — | 1,257 | ||||||
| Total | — | 1,257 | ||||||
Unsecured notes: | ||||||||
| 5.450% due 2015 | 150,000 | 150,000 | ||||||
| 6.400% due 2016 | 250,000 | 250,000 | ||||||
| 6.875% due 2036 | 350,000 | 350,000 | ||||||
| Total | 750,000 | 750,000 | ||||||
Pennsylvania Power Company- | ||||||||
First mortgage bonds: | ||||||||
| 9.740% due 2010-2019 | 8,799 | 9,773 | ||||||
| 6.090% due 2022 | 100,000 | 100,000 | ||||||
| 7.625% due 2023 | — | 6,500 | ||||||
| Total | 108,799 | 116,273 | ||||||
Secured notes: | ||||||||
| 5.400% due 2013 | — | 1,000 | ||||||
| Total | — | 1,000 | ||||||
| Capital lease obligations (Note 7) | 6,604 | 6,884 | ||||||
| Net unamortized discount on debt | (11,850 | ) | (12,483 | ) | ||||
| Long-term debt due within one year | (1,419 | ) | (2,723 | ) | ||||
| Total long-term debt and other long-term obligations | 1,152,134 | 1,160,208 | ||||||
TOTAL CAPITALIZATION | $ | 2,072,225 | $ | 2,187,760 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||
| Common Stock | Other | |||||||||||||||||||
| Comprehensive | Number | Carrying | Comprehensive | Retained | ||||||||||||||||
| (Dollars in thousands) | Income | of Shares | Value | Income (Loss) | Earnings | |||||||||||||||
| Balance, January 1, 2008 | 60 | $ | 1,220,512 | $ | 48,386 | $ | 307,277 | |||||||||||||
| Earnings available to parent | $ | 211,746 | 211,746 | |||||||||||||||||
| Change in unrealized gain on investments, net of $5,702 of income tax benefits | (10,370 | ) | (10,370 | ) | ||||||||||||||||
| Pension and other postretirement benefits, net of $121,425 of income tax benefits (Note 3) | (222,401 | ) | (222,401 | ) | ||||||||||||||||
| Comprehensive loss | $ | (21,025 | ) | |||||||||||||||||
| Restricted stock units | (16 | ) | ||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||
| Consolidated tax benefit allocation | 3,919 | |||||||||||||||||||
| Cash dividends declared on common stock | (265,000 | ) | ||||||||||||||||||
| Balance, December 31, 2008 | 60 | 1,224,416 | (184,385 | ) | 254,023 | |||||||||||||||
| Earnings available to parent | $ | 121,867 | 121,867 | |||||||||||||||||
| Change in unrealized gain on investments, net of $4,196 of income tax benefits | (5,497 | ) | (5,497 | ) | ||||||||||||||||
| Pension and other postretirement benefits, net of $20,257 of income taxes (Note 3) | 26,305 | 26,305 | ||||||||||||||||||
| Comprehensive income available to parent | $ | 142,675 | ||||||||||||||||||
| Restricted stock units | 81 | |||||||||||||||||||
| Consolidated tax benefit allocation | 4,300 | |||||||||||||||||||
| Cash dividends declared on common stock | (346,000 | ) | ||||||||||||||||||
| Cash dividends declared as return of capital | (74,000 | ) | ||||||||||||||||||
| Balance, December 31, 2009 | 60 | 1,154,797 | (163,577 | ) | 29,890 | |||||||||||||||
| Earnings available to parent | $ | 156,731 | 156,731 | |||||||||||||||||
| Unrealized gain on investments, net of $246 of income taxes | 448 | 448 | ||||||||||||||||||
| Pension and other postretirement benefits, net of $10,596 of income tax benefits (Note 3) | (15,947 | ) | (15,947 | ) | ||||||||||||||||
| Comprehensive income available to parent | $ | 141,232 | ||||||||||||||||||
| Restricted stock units | 117 | |||||||||||||||||||
| Consolidated tax benefit allocation | 1,952 | |||||||||||||||||||
| Cash dividends declared on common stock | (45,000 | ) | ||||||||||||||||||
| Cash dividends declared as return of capital | (205,000 | ) | ||||||||||||||||||
| Balance, December 31, 2010 | 60 | $ | 951,866 | $ | (179,076 | ) | $ | 141,621 | ||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 157,240 | $ | 122,434 | $ | 212,359 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 88,154 | 89,289 | 79,444 | |||||||||
| Amortization of regulatory assets, net | 62,857 | 93,694 | 117,733 | |||||||||
| Amortization of lease costs | (8,609 | ) | (8,211 | ) | (7,702 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 46,513 | 41,178 | 16,125 | |||||||||
| Accrued compensation and retirement benefits | (23,025 | ) | (13,729 | ) | 17,139 | |||||||
| Accrued regulatory obligations | 1,047 | 18,635 | — | |||||||||
| Electric service prepayment programs | — | (4,634 | ) | (42,215 | ) | |||||||
| Cash collateral from suppliers | 2,060 | 6,469 | — | |||||||||
| Pension trust contributions | — | (103,035 | ) | — | ||||||||
| Asset retirement obligation settlements | (10,075 | ) | — | — | ||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | 26,650 | 139,679 | (61,926 | ) | ||||||||
| Prepayments and other current assets | 13,639 | (10,407 | ) | 5,937 | ||||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (21,311 | ) | (14,949 | ) | 14,166 | |||||||
| Accrued taxes | (3,161 | ) | (9,142 | ) | (8,983 | ) | ||||||
| Accrued interest | (367 | ) | 76 | 3,295 | ||||||||
| Other | (4,712 | ) | 8,924 | 143 | ||||||||
| Net cash provided from operating activities | 326,900 | 356,271 | 345,515 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | — | 100,000 | 292,169 | |||||||||
| Short-term borrowings, net | 48,766 | 92,130 | — | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (10,075 | ) | (101,680 | ) | (249,897 | ) | ||||||
| Short-term borrowings, net | — | — | (51,761 | ) | ||||||||
| Common stock dividend payments | (250,000 | ) | (420,000 | ) | (315,000 | ) | ||||||
| Other | (1,561 | ) | (2,839 | ) | (4,435 | ) | ||||||
| Net cash used for financing activities | (212,870 | ) | (332,389 | ) | (328,924 | ) | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (150,119 | ) | (152,817 | ) | (182,512 | ) | ||||||
| Leasehold improvement payments from associated companies | 18,375 | — | — | |||||||||
| Sales of investment securities held in trusts | 83,352 | 131,478 | 120,744 | |||||||||
| Purchases of investment securities held in trusts | (89,406 | ) | (138,925 | ) | (127,680 | ) | ||||||
| Loan repayments from associated companies, net | 101,694 | 102,314 | 373,138 | |||||||||
| Collection of principal on long-term notes receivable | — | 195,970 | 1,756 | |||||||||
| Cash investments | 25,005 | 20,133 | (57,792 | ) | ||||||||
| Other | (6,617 | ) | (4,203 | ) | 1,366 | |||||||
| Net cash provided from (used for) investing activities | (17,716 | ) | 153,950 | 129,020 | ||||||||
| Net increase in cash and cash equivalents | 96,314 | 177,832 | 145,611 | |||||||||
| Cash and cash equivalents at beginning of year | 324,175 | 146,343 | 732 | |||||||||
| Cash and cash equivalents at end of year | 420,489 | $ | 324,175 | $ | 146,343 | |||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 82,895 | $ | 86,523 | $ | 67,508 | ||||||
| Income taxes | $ | 76,152 | $ | 20,530 | $ | 118,834 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES (Note 17): | ||||||||||||
| Electric sales | $ | 1,152,950 | $ | 1,609,946 | $ | 1,746,309 | ||||||
| Excise and gross receipts tax collections | 68,422 | 66,192 | 69,578 | |||||||||
| Total revenues | 1,221,372 | 1,676,138 | 1,815,887 | |||||||||
EXPENSES (Note 17): | ||||||||||||
| Purchased power from affiliates | 361,317 | 734,592 | 766,270 | |||||||||
| Purchased power from non-affiliates | 129,054 | 245,809 | 4,210 | |||||||||
| Other operating costs | 130,018 | 161,407 | 259,438 | |||||||||
| Provision for depreciation | 72,753 | 71,908 | 72,383 | |||||||||
| Amortization of regulatory assets, net | 169,541 | 370,967 | 163,534 | |||||||||
| Deferral of new regulatory assets | — | (134,587 | ) | (107,571 | ) | |||||||
| General taxes | 143,294 | 145,324 | 143,058 | |||||||||
| Total expenses | 1,005,977 | 1,595,420 | 1,301,322 | |||||||||
OPERATING INCOME | 215,395 | 80,718 | 514,565 | |||||||||
OTHER INCOME (EXPENSE) (Note 17): | ||||||||||||
| Investment income | 27,360 | 31,194 | 34,392 | |||||||||
| Miscellaneous income (expense) | 2,362 | 3,911 | (495 | ) | ||||||||
| Interest expense | (133,351 | ) | (137,171 | ) | (125,976 | ) | ||||||
| Capitalized interest | 82 | 173 | 786 | |||||||||
| Total other income (expense) | (103,547 | ) | (101,893 | ) | (91,293 | ) | ||||||
INCOME (LOSS) BEFORE INCOME TAXES | 111,848 | (21,175 | ) | 423,272 | ||||||||
INCOME TAXES | 38,673 | (10,183 | ) | 136,786 | ||||||||
NET INCOME (LOSS) | 73,175 | (10,992 | ) | 286,486 | ||||||||
| Income from noncontrolling interest | 1,517 | 1,714 | 1,960 | |||||||||
EARNINGS AVAILABLE TO PARENT | $ | 71,658 | $ | (12,706 | ) | $ | 284,526 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 238 | $ | 86,230 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $4,589 in 2010 and $5,239 in 2009 | 183,744 | 209,335 | ||||||
| Associated companies | 77,047 | 98,954 | ||||||
| Other | 11,544 | 11,661 | ||||||
| Notes receivable from associated companies | 23,236 | 26,802 | ||||||
| Prepayments and other | 3,656 | 9,973 | ||||||
| 299,465 | 442,955 | |||||||
UTILITY PLANT: | ||||||||
| In service | 2,396,893 | 2,310,074 | ||||||
| Less — Accumulated provision for depreciation | 932,246 | 888,169 | ||||||
| 1,464,647 | 1,421,905 | |||||||
| Construction work in progress | 38,610 | 36,907 | ||||||
| 1,503,257 | 1,458,812 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Investment in lessor notes | 340,029 | 388,641 | ||||||
| Other | 10,074 | 10,220 | ||||||
| 350,103 | 398,861 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 1,688,521 | 1,688,521 | ||||||
| Regulatory assets | 370,403 | 545,505 | ||||||
| Pension assets (Note 3) | — | 13,380 | ||||||
| Property taxes | 80,614 | 77,319 | ||||||
| Other | 11,486 | 12,777 | ||||||
| 2,151,024 | 2,337,502 | |||||||
| $ | 4,303,849 | $ | 4,638,130 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 161 | $ | 117 | ||||
| Short-term borrowings- | ||||||||
| Associated companies | 105,996 | 339,728 | ||||||
| Accounts payable- | ||||||||
| Associated companies | 32,020 | 68,634 | ||||||
| Other | 14,947 | 17,166 | ||||||
| Accrued taxes | 84,668 | 90,511 | ||||||
| Accrued interest | 18,555 | 18,466 | ||||||
| Other | 44,569 | 45,440 | ||||||
| 300,916 | 580,062 | |||||||
CAPITALIZATION (See Consolidated Statement of Capitalization): | ||||||||
| Common stockholder’s equity | 1,302,806 | 1,343,987 | ||||||
| Noncontrolling interest | 18,017 | 20,592 | ||||||
| Total equity | 1,320,823 | 1,364,579 | ||||||
| Long-term debt and other long-term obligations | 1,852,530 | 1,872,750 | ||||||
| 3,173,353 | 3,237,329 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 622,771 | 644,745 | ||||||
| Accumulated deferred investment tax credits | 10,994 | 11,836 | ||||||
| Retirement benefits | 95,654 | 69,733 | ||||||
| Other | 100,161 | 94,425 | ||||||
| 829,580 | 820,739 | |||||||
COMMITMENTS AND CONTINGENCIES (Note 7 and 14) | ||||||||
| $ | 4,303,849 | $ | 4,638,130 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, without par value, 105,000,000 shares authorized, 67,930,743 shares outstanding | $ | 887,087 | $ | 884,897 | ||||
| Accumulated other comprehensive loss (Note 2(F)) | (153,187 | ) | (138,158 | ) | ||||
| Retained earnings (Note 11(A)) | 568,906 | 597,248 | ||||||
| Total | 1,302,806 | 1,343,987 | ||||||
NONCONTROLLING INTEREST | 18,017 | 20,592 | ||||||
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)): | ||||||||
| First mortgage bonds- | ||||||||
| 8.875% due 2018 | 300,000 | 300,000 | ||||||
| 5.500% due 2024 | 300,000 | 300,000 | ||||||
| Total | 600,000 | 600,000 | ||||||
| Secured notes- | ||||||||
| 7.880% due 2017 | 300,000 | 300,000 | ||||||
| Total | 300,000 | 300,000 | ||||||
| Unsecured notes- | ||||||||
| 5.650% due 2013 | 300,000 | 300,000 | ||||||
| 5.700% due 2017 | 250,000 | 250,000 | ||||||
| 5.950% due 2036 | 300,000 | 300,000 | ||||||
| 7.663% due to associated companies 2010-2016 (Note 8) | 102,692 | 123,008 | ||||||
| Total | 952,692 | 973,008 | ||||||
| Capital lease obligations (Note 7) | 3,044 | 3,162 | ||||||
| Net unamortized discount on debt | (3,045 | ) | (3,303 | ) | ||||
| Long-term debt due within one year | (161 | ) | (117 | ) | ||||
| Total long-term debt and other long-term obligations | 1,852,530 | 1,872,750 | ||||||
TOTAL CAPITALIZATION | $ | 3,173,353 | $ | 3,237,329 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||
| Common Stock | Other | |||||||||||||||||||
| Comprehensive | Number | Carrying | Comprehensive | Retained | ||||||||||||||||
| (Dollars in thousands) | Income | of Shares | Value | Income (Loss) | Earnings | |||||||||||||||
| Balance, January 1, 2008 | 67,930,743 | $ | 873,536 | $ | (69,129 | ) | $ | 685,428 | ||||||||||||
| Earnings available to parent | $ | 284,526 | 284,526 | |||||||||||||||||
| Pension and other postretirement benefits, net of $33,136 of income tax benefits (Note 3) | (65,728 | ) | (65,728 | ) | ||||||||||||||||
| Comprehensive income | $ | 218,798 | ||||||||||||||||||
| Restricted stock units | (1 | ) | ||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||
| Consolidated tax benefit allocation | 5,249 | |||||||||||||||||||
| Cash dividends declared on common stock | (110,000 | ) | ||||||||||||||||||
| Balance, December 31, 2008 | 67,930,743 | 878,785 | (134,857 | ) | 859,954 | |||||||||||||||
| Loss applicable to parent | $ | (12,706 | ) | (12,706 | ) | |||||||||||||||
| Pension and other postretirement benefits, net of $1,923 of income taxes (Note 3) | (3,301 | ) | (3,301 | ) | ||||||||||||||||
| Comprehensive loss | $ | (16,007 | ) | |||||||||||||||||
| Restricted stock units | 74 | |||||||||||||||||||
| Consolidated tax benefit allocation | 6,038 | |||||||||||||||||||
| Cash dividends declared on common stock | (250,000 | ) | ||||||||||||||||||
| Balance, December 31, 2009 | 67,930,743 | 884,897 | (138,158 | ) | 597,248 | |||||||||||||||
| Earnings available to parent | $ | 71,658 | 71,658 | |||||||||||||||||
| Pension and other postretirement benefits, net of $11,926 of income tax benefits (Note 3) | (15,029 | ) | (15,029 | ) | ||||||||||||||||
| Comprehensive loss | $ | 56,629 | ||||||||||||||||||
| Restricted stock units | 55 | |||||||||||||||||||
| Consolidated tax benefit allocation | 2,135 | |||||||||||||||||||
| Cash dividends declared on common stock | (100,000 | ) | ||||||||||||||||||
| Balance, December 31, 2010 | 67,930,743 | $ | 887,087 | $ | (153,187 | ) | $ | 568,906 | ||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income (loss) | $ | 73,175 | $ | (10,992 | ) | $ | 286,486 | |||||
| Adjustments to reconcile net income (loss) to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 72,753 | 71,908 | 72,383 | |||||||||
| Amortization of regulatory assets | 169,541 | 370,967 | 163,534 | |||||||||
| Deferral of new regulatory assets | — | (134,587 | ) | (107,571 | ) | |||||||
| Deferred income taxes and investment tax credits, net | (20,068 | ) | (51,839 | ) | 11,918 | |||||||
| Accrued compensation and retirement benefits | 12,724 | 8,514 | 1,563 | |||||||||
| Accrued regulatory obligations | — | 12,556 | — | |||||||||
| Electric service prepayment programs | — | (3,510 | ) | (23,634 | ) | |||||||
| Cash collateral from suppliers | 889 | 5,440 | — | |||||||||
| Lease assignment payments to associated company | — | (40,827 | ) | — | ||||||||
| Pension trust contributions | — | (89,789 | ) | — | ||||||||
| Uncertain tax positions | (2,872 | ) | 10,766 | (793 | ) | |||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | 60,762 | 65,603 | 66,963 | |||||||||
| Prepayments and other current assets | 6,075 | (7,186 | ) | (450 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (38,833 | ) | (3,479 | ) | 13,787 | |||||||
| Accrued taxes | (3,700 | ) | 2,533 | (3,149 | ) | |||||||
| Accrued interest | 89 | 4,534 | 37 | |||||||||
| Other | 2,090 | (3,736 | ) | 8,995 | ||||||||
| Net cash provided from operating activities | 332,625 | 206,876 | 490,069 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | — | 298,398 | 300,000 | |||||||||
| Short-term borrowings, net | — | 93,577 | — | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (117 | ) | (151,273 | ) | (213,319 | ) | ||||||
| Short-term borrowings, net | (254,048 | ) | — | (315,827 | ) | |||||||
| Common stock dividend payments | (100,000 | ) | (275,000 | ) | (185,000 | ) | ||||||
| Other | (4,100 | ) | (6,427 | ) | (6,440 | ) | ||||||
| Net cash used for financing activities | (358,265 | ) | (40,725 | ) | (420,586 | ) | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (105,660 | ) | (103,243 | ) | (137,265 | ) | ||||||
| Loan repayments from (loans to) associated companies, net | 3,566 | (7,741 | ) | 33,246 | ||||||||
| Investment in lessor notes | 48,612 | 37,074 | 37,707 | |||||||||
| Other | (6,870 | ) | (6,237 | ) | (3,177 | ) | ||||||
| Net cash used for investing activities | (60,352 | ) | (80,147 | ) | (69,489 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | (85,992 | ) | 86,004 | (6 | ) | |||||||
| Cash and cash equivalents at beginning of year | 86,230 | 226 | 232 | |||||||||
| Cash and cash equivalents at end of year | $ | 238 | $ | 86,230 | $ | 226 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 131,546 | $ | 130,689 | $ | 122,834 | ||||||
| Income taxes | $ | 67,651 | $ | 29,358 | $ | 153,042 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES (Note 17): | ||||||||||||
| Electric sales | $ | 489,310 | $ | 810,069 | $ | 865,016 | ||||||
| Excise tax collections | 27,387 | 23,839 | 30,489 | |||||||||
| Total revenues | 516,697 | 833,908 | 895,505 | |||||||||
EXPENSES (Note 17): | ||||||||||||
| Purchased power from affiliates | 180,523 | 392,825 | 410,885 | |||||||||
| Purchased power from non-affiliates | 64,174 | 136,210 | 2,459 | |||||||||
| Other operating costs | 108,072 | 142,203 | 190,441 | |||||||||
| Provision for depreciation | 31,613 | 30,727 | 32,422 | |||||||||
| Amortization (deferral) of regulatory assets, net | (1,427 | ) | 37,820 | 94,104 | ||||||||
| General taxes | 52,045 | 47,815 | 52,324 | |||||||||
| Total expenses | 435,000 | 787,600 | 782,635 | |||||||||
OPERATING INCOME | 81,697 | 46,308 | 112,870 | |||||||||
OTHER INCOME (EXPENSE) (Note 17): | ||||||||||||
| Investment income | 14,727 | 24,388 | 22,823 | |||||||||
| Miscellaneous expense | (4,206 | ) | (2,436 | ) | (7,820 | ) | ||||||
| Interest expense | (41,883 | ) | (36,512 | ) | (23,286 | ) | ||||||
| Capitalized interest | 358 | 169 | 164 | |||||||||
| Total other expense | (31,004 | ) | (14,391 | ) | (8,119 | ) | ||||||
INCOME BEFORE INCOME TAXES | 50,693 | 31,917 | 104,751 | |||||||||
INCOME TAXES | 17,645 | 7,939 | 29,824 | |||||||||
NET INCOME | 33,048 | 23,978 | 74,927 | |||||||||
| Income from noncontrolling interest | 4 | 21 | 12 | |||||||||
EARNINGS AVAILABLE TO PARENT | $ | 33,044 | $ | 23,957 | $ | 74,915 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 149,262 | $ | 436,712 | ||||
| Receivables- | ||||||||
| Customers | 29 | 75 | ||||||
| Associated companies | 31,777 | 90,191 | ||||||
| Other, net of allowance for uncollectible accounts of $330 in 2010 and $208 in 2009 | 18,464 | 20,180 | ||||||
| Notes receivable from associated companies | 96,765 | 85,101 | ||||||
| Prepayments and other | 2,306 | 7,111 | ||||||
| 298,603 | 639,370 | |||||||
UTILITY PLANT: | ||||||||
| In service | 947,203 | 912,930 | ||||||
| Less — Accumulated provision for depreciation | 446,401 | 427,376 | ||||||
| 500,802 | 485,554 | |||||||
| Construction work in progress | 12,604 | 9,069 | ||||||
| 513,406 | 494,623 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Investment in lessor notes (Note 7) | 103,872 | 124,357 | ||||||
| Nuclear plant decommissioning trusts | 75,558 | 73,935 | ||||||
| Other | 1,492 | 1,580 | ||||||
| 180,922 | 199,872 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 500,576 | 500,576 | ||||||
| Regulatory assets | 72,059 | 69,557 | ||||||
| Property taxes | 24,990 | 23,658 | ||||||
| Other | 23,750 | 55,622 | ||||||
| 621,375 | 649,413 | |||||||
| $ | 1,614,306 | $ | 1,983,278 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 199 | $ | 222 | ||||
| Accounts payable- | ||||||||
| Associated companies | 17,168 | 78,341 | ||||||
| Other | 7,351 | 8,312 | ||||||
| Notes payable to associated companies | — | 225,975 | ||||||
| Accrued taxes | 24,401 | 25,734 | ||||||
| Lease market valuation liability | 36,900 | 36,900 | ||||||
| Other | 29,076 | 29,273 | ||||||
| 115,095 | 404,757 | |||||||
CAPITALIZATION (See Consolidated Statements of Capitalization): | ||||||||
| Common stockholder’s equity | 393,543 | 489,878 | ||||||
| Noncontrolling interest | 2,589 | 2,696 | ||||||
| Total equity | 396,132 | 492,574 | ||||||
| Long-term debt and other long-term obligations | 600,493 | 600,443 | ||||||
| 996,625 | 1,093,017 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 132,019 | 80,508 | ||||||
| Accumulated deferred investment tax credits | 5,930 | 6,367 | ||||||
| Retirement benefits | 71,486 | 65,988 | ||||||
| Asset retirement obligations | 28,762 | 32,290 | ||||||
| Lease market valuation liability (Note 7) | 199,300 | 236,200 | ||||||
| Other | 65,089 | 64,151 | ||||||
| 502,586 | 485,504 | |||||||
COMMITMENTS AND CONTINGENCIES (Notes 7 and 14) | ||||||||
| $ | 1,614,306 | $ | 1,983,278 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, $5 par value, 60,000,000 shares authorized, 29,402,054 shares outstanding | $ | 147,010 | $ | 147,010 | ||||
| Other paid-in capital | 178,182 | 178,181 | ||||||
| Accumulated other comprehensive loss (Note 2(F)) | (49,183 | ) | (49,803 | ) | ||||
| Retained earnings (Note 11(A)) | 117,534 | 214,490 | ||||||
| Total | 393,543 | 489,878 | ||||||
NONCONTROLLING INTEREST | 2,589 | 2,696 | ||||||
LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS (Note 11(C)): | ||||||||
| Secured notes- | ||||||||
| 7.250% due 2020 | 300,000 | 300,000 | ||||||
| 6.150% due 2037 | 300,000 | 300,000 | ||||||
| Total | 600,000 | 600,000 | ||||||
| Capital lease obligations (Note 7) | 3,270 | 3,492 | ||||||
| Net unamortized discount on debt | (2,578 | ) | (2,827 | ) | ||||
| Long-term debt due within one year | (199 | ) | (222 | ) | ||||
| Total long-term debt and other long-term obligations | 600,493 | 600,443 | ||||||
TOTAL CAPITALIZATION | $ | 996,625 | $ | 1,093,017 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||||||
| Common Stock | Other | Other | ||||||||||||||||||||||
| Comprehensive | Number | Par | Paid-In | Comprehensive | Retained | |||||||||||||||||||
| (Dollars in thousands) | Income | of Shares | Value | Capital | Income (Loss) | Earnings | ||||||||||||||||||
| Balance, January 1, 2008 | 29,402,054 | $ | 147,010 | $ | 173,169 | $ | (10,606 | ) | $ | 175,618 | ||||||||||||||
| Earnings available to parent | $ | 74,915 | 74,915 | |||||||||||||||||||||
| Unrealized gain on investments, net of $1,421 of income taxes | 2,372 | 2,372 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $11,630 of income tax benefits (Note 3) | (25,138 | ) | (25,138 | ) | ||||||||||||||||||||
| Comprehensive income available to parent | $ | 52,149 | ||||||||||||||||||||||
| Restricted stock units | 47 | |||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Consolidated tax benefit allocation | 2,662 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (60,000 | ) | ||||||||||||||||||||||
| Balance, December 31, 2008 | 29,402,054 | 147,010 | 175,879 | (33,372 | ) | 190,533 | ||||||||||||||||||
| Earnings available to parent | $ | 23,957 | 23,957 | |||||||||||||||||||||
| Change in unrealized gain on investments, net of $5,756 of income tax benefits | (9,425 | ) | (9,425 | ) | ||||||||||||||||||||
| Pension and other postretirement benefits, net of $874 of income tax benefits (Note 3) | (7,006 | ) | (7,006 | ) | ||||||||||||||||||||
| Comprehensive income available to parent | $ | 7,526 | ||||||||||||||||||||||
| Restricted stock units | 71 | |||||||||||||||||||||||
| Consolidated tax benefit allocation | 2,231 | |||||||||||||||||||||||
| Balance, December 31, 2009 | 29,402,054 | 147,010 | 178,181 | (49,803 | ) | 214,490 | ||||||||||||||||||
| Earnings available to parent | $ | 33,044 | 33,044 | |||||||||||||||||||||
| Unrealized gain on investments, net of $46 of income taxes | 85 | 85 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $1,190 of income tax benefits (Note 3) | 535 | 535 | ||||||||||||||||||||||
| Comprehensive income available to parent | $ | 33,664 | ||||||||||||||||||||||
| Restricted stock units | 1 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (130,000 | ) | ||||||||||||||||||||||
| Balance, December 31, 2010 | 29,402,054 | $ | 147,010 | $ | 178,182 | $ | (49,183 | ) | $ | 117,534 | ||||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 33,048 | $ | 23,978 | $ | 74,927 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 31,613 | 30,727 | 32,422 | |||||||||
| Amortization (deferral) of regulatory assets, net | (1,427 | ) | 37,820 | 94,104 | ||||||||
| Deferred rents and lease market valuation liability | (37,839 | ) | (37,839 | ) | (37,938 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 28,041 | 2,003 | (16,869 | ) | ||||||||
| Accrued compensation and retirement benefits | 5,517 | 3,489 | 1,483 | |||||||||
| Accrued regulatory obligations | (36 | ) | 4,630 | — | ||||||||
| Electric service prepayment programs | — | (1,458 | ) | (11,181 | ) | |||||||
| Pension trust contribution | — | (21,590 | ) | — | ||||||||
| Cash collateral from suppliers | 1,548 | 2,794 | — | |||||||||
| Lease assignment payment to associated company | — | (30,529 | ) | — | ||||||||
| Gain on sales of investment securities held in trusts | (2,348 | ) | (7,130 | ) | (626 | ) | ||||||
| Uncertain tax positions | (1,831 | ) | 3,038 | (1,219 | ) | |||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | 82,369 | (18,872 | ) | 20,186 | ||||||||
| Prepayments and other current assets | 6,464 | (5,898 | ) | (348 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (60,183 | ) | 35,192 | (164,397 | ) | |||||||
| Accrued taxes | (1,333 | ) | (1,932 | ) | (5,812 | ) | ||||||
| Accrued interest | — | 3,625 | (17 | ) | ||||||||
| Other | (7,653 | ) | (1,120 | ) | (1,456 | ) | ||||||
| Net cash provided from (used for) operating activities | 75,950 | 20,928 | (16,741 | ) | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | — | 297,422 | — | |||||||||
| Short-term borrowings, net | — | 114,733 | 97,846 | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (222 | ) | (347 | ) | (3,860 | ) | ||||||
| Short-term borrowings, net | (225,975 | ) | — | — | ||||||||
| Common stock dividend payments | (130,000 | ) | (25,000 | ) | (70,000 | ) | ||||||
| Other | (112 | ) | (351 | ) | (131 | ) | ||||||
| Net cash provided from (used for) financing activities | (356,309 | ) | 386,457 | 23,855 | ||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (42,097 | ) | (47,028 | ) | (57,385 | ) | ||||||
| Leasehold improvement payments from associated companies | 32,829 | — | — | |||||||||
| Loan repayments from (loans to) associated companies, net | (11,664 | ) | 63,711 | 43,098 | ||||||||
| Redemption of lessor notes (Note 7) | 20,485 | 18,330 | 11,959 | |||||||||
| Sales of investment securities held in trusts | 125,557 | 168,580 | 37,931 | |||||||||
| Purchases of investment securities held in trusts | (127,323 | ) | (170,996 | ) | (40,960 | ) | ||||||
| Other | (4,878 | ) | (3,284 | ) | (1,765 | ) | ||||||
| Net cash provided from (used for) investing activities | (7,091 | ) | 29,313 | (7,122 | ) | |||||||
| Net increase (decrease) in cash and cash equivalents | (287,450 | ) | 436,698 | (8 | ) | |||||||
| Cash and cash equivalents at beginning of year | 436,712 | 14 | 22 | |||||||||
| Cash and cash equivalents at end of year | 149,262 | $ | 436,712 | $ | 14 | |||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid (received) during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 41,162 | $ | 32,353 | $ | 22,203 | ||||||
| Income taxes | $ | (13,456 | ) | $ | 1,350 | $ | 62,879 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES: | ||||||||||||
| Electric sales | $ | 2,976,452 | $ | 2,943,590 | $ | 3,420,772 | ||||||
| Excise tax collections | 50,636 | 49,097 | 51,481 | |||||||||
| Total revenues | 3,027,088 | 2,992,687 | 3,472,253 | |||||||||
EXPENSES: | ||||||||||||
| Purchased power | 1,736,318 | 1,782,435 | 2,206,251 | |||||||||
| Other operating costs | 344,135 | 309,791 | 302,894 | |||||||||
| Provision for depreciation | 107,167 | 102,912 | 96,482 | |||||||||
| Amortization of regulatory assets | 320,561 | 344,158 | 364,816 | |||||||||
| General taxes | 65,396 | 63,078 | 67,340 | |||||||||
| Total expenses | 2,573,577 | 2,602,374 | 3,037,783 | |||||||||
OPERATING INCOME | 453,511 | 390,313 | 434,470 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
| Miscellaneous income (expense) | 6,303 | 5,272 | (1,037 | ) | ||||||||
| Interest expense (Note 17) | (120,152 | ) | (116,851 | ) | (99,459 | ) | ||||||
| Capitalized interest | 697 | 543 | 1,245 | |||||||||
| Total other expense | (113,152 | ) | (111,036 | ) | (99,251 | ) | ||||||
INCOME BEFORE INCOME TAXES | 340,359 | 279,277 | 335,219 | |||||||||
INCOME TAXES | 148,264 | 108,778 | 148,231 | |||||||||
NET INCOME | $ | 192,095 | $ | 170,499 | $ | 186,988 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars In thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 4 | $ | 27 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $3,769 in 2010 and $3,506 in 2009 | 323,044 | 300,991 | ||||||
| Associated companies | 53,780 | 12,884 | ||||||
| Other | 26,119 | 21,877 | ||||||
| Notes receivable — associated companies | 177,228 | 102,932 | ||||||
| Prepaid taxes | 10,889 | 34,930 | ||||||
| Other | 12,654 | 12,945 | ||||||
| 603,718 | 486,586 | |||||||
UTILITY PLANT: | ||||||||
| In service | 4,562,781 | 4,463,490 | ||||||
| Less — Accumulated provision for depreciation | 1,656,939 | 1,617,639 | ||||||
| 2,905,842 | 2,845,851 | |||||||
| Construction work in progress | 63,535 | 54,251 | ||||||
| 2,969,377 | 2,900,102 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Nuclear fuel disposal trust | 207,561 | 199,677 | ||||||
| Nuclear plant decommissioning trusts | 181,851 | 166,768 | ||||||
| Other | 2,104 | 2,149 | ||||||
| 391,516 | 368,594 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 1,810,936 | 1,810,936 | ||||||
| Regulatory assets | 513,395 | 888,143 | ||||||
| Other | 27,938 | 27,096 | ||||||
| 2,352,269 | 2,726,175 | |||||||
| $ | 6,316,880 | $ | 6,481,457 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 32,402 | $ | 30,667 | ||||
| Accounts payable- | ||||||||
| Associated companies | 28,571 | 26,882 | ||||||
| Other | 158,442 | 168,093 | ||||||
| Accrued compensation and benefits | 35,232 | 32,814 | ||||||
| Customer deposits | 23,385 | 23,636 | ||||||
| Accrued interest | 18,111 | 18,256 | ||||||
| Other | 24,772 | 67,272 | ||||||
| 320,915 | 367,620 | |||||||
CAPITALIZATION (See Consolidated Statements of Capitalization): | ||||||||
| Common stockholder’s equity | 2,618,786 | 2,600,396 | ||||||
| Long-term debt and other long-term obligations | 1,769,849 | 1,801,589 | ||||||
| 4,388,635 | 4,401,985 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 715,527 | 687,545 | ||||||
| Power purchase contract liability | 233,492 | 399,105 | ||||||
| Nuclear fuel disposal costs | 196,768 | 196,511 | ||||||
| Retirement benefits | 182,364 | 150,603 | ||||||
| Asset retirement obligations | 108,297 | 101,568 | ||||||
| Other | 170,882 | 176,520 | ||||||
| 1,607,330 | 1,711,852 | |||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 7 and 14) | ||||||||
| $ | 6,316,880 | $ | 6,481,457 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, $10 par value, 16,000,000 shares authorized, 13,628,447 shares outstanding | $ | 136,284 | $ | 136,284 | ||||
| Other paid-in capital | 2,508,874 | 2,507,049 | ||||||
| Accumulated other comprehensive loss (Note 2(F)) | (253,542 | ) | (243,012 | ) | ||||
| Retained earnings (Note 11(A)) | 227,170 | 200,075 | ||||||
| Total | 2,618,786 | 2,600,396 | ||||||
LONG-TERM DEBT (Note 11(C)): | ||||||||
| Secured notes- | ||||||||
| 5.390% due 2008-2010 | — | 13,629 | ||||||
| 5.250% due 2008-2012 | 14,268 | 23,974 | ||||||
| 5.810% due 2010-2013 | 69,772 | 77,075 | ||||||
| 5.410% due 2012-2014 | 25,693 | 25,693 | ||||||
| 6.160% due 2013-2017 | 99,517 | 99,517 | ||||||
| 5.520% due 2014-2018 | 49,220 | 49,220 | ||||||
| 5.610% due 2018-2021 | 51,139 | 51,139 | ||||||
| Total | 309,609 | 340,247 | ||||||
| Unsecured notes- | ||||||||
| 5.625% due 2016 | 300,000 | 300,000 | ||||||
| 5.650% due 2017 | 250,000 | 250,000 | ||||||
| 4.800% due 2018 | 150,000 | 150,000 | ||||||
| 7.350% due 2019 | 300,000 | 300,000 | ||||||
| 6.400% due 2036 | 200,000 | 200,000 | ||||||
| 6.150% due 2037 | 300,000 | 300,000 | ||||||
| Total | 1,500,000 | 1,500,000 | ||||||
| Capital lease obligations (Note 7) | 108 | 136 | ||||||
| Unamortized discount on debt | (7,466 | ) | (8,127 | ) | ||||
| Long-term debt due within one year | (32,402 | ) | (30,667 | ) | ||||
| Total long-term debt | 1,769,849 | 1,801,589 | ||||||
TOTAL CAPITALIZATION | $ | 4,388,635 | $ | 4,401,985 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||||||
| Common Stock | Other | Other | ||||||||||||||||||||||
| Comprehensive | Number | Par | Paid-In | Comprehensive | Retained | |||||||||||||||||||
| (Dollars in thousands) | Income | of Shares | Value | Capital | Income (Loss) | Earnings | ||||||||||||||||||
| Balance, January 1, 2008 | 14,421,637 | $ | 144,216 | $ | 2,655,941 | $ | (19,881 | ) | $ | 237,588 | ||||||||||||||
| Net income | $ | 186,988 | 186,988 | |||||||||||||||||||||
| Net unrealized gain on derivative instruments | 276 | 276 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $131,317 of income tax benefits (Note 3) | (196,933 | ) | (196,933 | ) | ||||||||||||||||||||
| Comprehensive loss | $ | (9,669 | ) | |||||||||||||||||||||
| Restricted stock units | 3 | |||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Consolidated tax benefit allocation | 4,065 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (268,000 | ) | ||||||||||||||||||||||
| Purchase accounting fair value adjustment | (15,254 | ) | ||||||||||||||||||||||
| Balance, December 31, 2008 | 14,421,637 | 144,216 | 2,644,756 | (216,538 | ) | 156,576 | ||||||||||||||||||
| Net income | $ | 170,499 | 170,499 | |||||||||||||||||||||
| Net unrealized gain on derivative instruments, net of $11 of income tax benefits | 288 | 288 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $13,025 of income tax benefits (Note 3) | (26,762 | ) | (26,762 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 144,025 | ||||||||||||||||||||||
| Restricted stock units | 99 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (127,000 | ) | ||||||||||||||||||||||
| Repurchase of common stock | (793,190 | ) | (7,932 | ) | (137,806 | ) | ||||||||||||||||||
| Balance, December 31, 2009 | 13,628,447 | 136,284 | 2,507,049 | (243,012 | ) | 200,075 | ||||||||||||||||||
| Net income | $ | 192,095 | 192,095 | |||||||||||||||||||||
| Net unrealized loss on derivative instruments, net of $463 of income taxes | (187 | ) | (187 | ) | ||||||||||||||||||||
| Pension and other postretirement benefits, net of $9,065 of income tax benefits (Note 3) | (10,343 | ) | (10,343 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 181,565 | ||||||||||||||||||||||
| Restricted stock units | 59 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (165,000 | ) | ||||||||||||||||||||||
| Consolidated tax benefit allocation | 1,766 | |||||||||||||||||||||||
| Balance, December 31, 2010 | 13,628,447 | $ | 136,284 | $ | 2,508,874 | $ | (253,542 | ) | $ | 227,170 | ||||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 192,095 | $ | 170,499 | $ | 186,988 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 107,167 | 102,912 | 96,482 | |||||||||
| Amortization of regulatory assets | 320,561 | 344,158 | 364,816 | |||||||||
| Deferred purchased power and other costs | (104,842 | ) | (148,308 | ) | (165,071 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 31,645 | 42,800 | 12,834 | |||||||||
| Accrued compensation and retirement benefits | 14,055 | 12,915 | (35,791 | ) | ||||||||
| Cash collateral from (returned to) suppliers | (22,341 | ) | (210 | ) | 23,106 | |||||||
| Pension trust contributions | — | (100,000 | ) | — | ||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | (67,191 | ) | 42,532 | 8,042 | ||||||||
| Prepayments and other current assets | 23,595 | (24,333 | ) | (9,252 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (19,465 | ) | (24,677 | ) | 10,174 | |||||||
| Accrued taxes | 11,739 | (14,265 | ) | 2,582 | ||||||||
| Accrued interest | (145 | ) | 9,059 | (121 | ) | |||||||
| Other | (9,966 | ) | (11,246 | ) | (13,002 | ) | ||||||
| Net cash provided from operating activities | 476,907 | 401,836 | 481,787 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | — | 299,619 | — | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (30,639 | ) | (29,094 | ) | (27,206 | ) | ||||||
| Short-term borrowings, net | — | (121,380 | ) | (9,001 | ) | |||||||
| Common stock | — | (150,000 | ) | — | ||||||||
| Common stock dividend payments | (165,000 | ) | (127,000 | ) | (268,000 | ) | ||||||
| Other | (2 | ) | (2,281 | ) | (80 | ) | ||||||
| Net cash used for financing activities | (195,641 | ) | (130,136 | ) | (304,287 | ) | ||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (182,368 | ) | (166,409 | ) | (178,358 | ) | ||||||
| Proceeds from asset sales | — | — | 20,000 | |||||||||
| Loan repayments from (loans to) associated companies, net | (74,296 | ) | (86,678 | ) | 2,173 | |||||||
| Sales of investment securities held in trusts | 411,470 | 397,333 | 248,185 | |||||||||
| Purchases of investment securities held in trusts | (428,214 | ) | (413,693 | ) | (265,441 | ) | ||||||
| Restricted funds | (1,322 | ) | 5,015 | (689 | ) | |||||||
| Other | (6,559 | ) | (7,307 | ) | (3,398 | ) | ||||||
| Net cash used for investing activities | (281,289 | ) | (271,739 | ) | (177,528 | ) | ||||||
| Net decrease in cash and cash equivalents | (23 | ) | (39 | ) | (28 | ) | ||||||
| Cash and cash equivalents at beginning of year | 27 | 66 | 94 | |||||||||
| Cash and cash equivalents at end of year | $ | 4 | $ | 27 | $ | 66 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 117,454 | $ | 108,650 | $ | 99,731 | ||||||
| Income taxes | $ | 144,939 | $ | 95,764 | $ | 145,943 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES: | ||||||||||||
| Electric sales | $ | 1,733,651 | $ | 1,611,088 | $ | 1,573,781 | ||||||
| Excise tax collections | 84,896 | 77,894 | 79,221 | |||||||||
| Total revenues | 1,818,547 | 1,688,982 | 1,653,002 | |||||||||
EXPENSES (Note 17): | ||||||||||||
| Purchased power from affiliates | 612,496 | 365,491 | 303,779 | |||||||||
| Purchased power from non-affiliates | 342,988 | 536,054 | 593,203 | |||||||||
| Other operating costs | 418,569 | 277,024 | 429,745 | |||||||||
| Provision for depreciation | 52,176 | 51,006 | 44,556 | |||||||||
| Amortization of regulatory assets, net | 160,360 | 244,709 | 21,504 | |||||||||
| General taxes | 87,829 | 87,799 | 85,643 | |||||||||
| Total expenses | 1,674,418 | 1,562,083 | 1,478,430 | |||||||||
OPERATING INCOME | 144,129 | 126,899 | 174,572 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
| Interest income | 3,019 | 9,709 | 17,647 | |||||||||
| Miscellaneous income | 5,901 | 4,033 | 105 | |||||||||
| Interest expense (Note 17) | (52,829 | ) | (56,683 | ) | (43,651 | ) | ||||||
| Capitalized interest | 653 | 159 | 258 | |||||||||
| Total other expense | (43,256 | ) | (42,782 | ) | (25,641 | ) | ||||||
INCOME BEFORE INCOME TAXES | 100,873 | 84,117 | 148,931 | |||||||||
INCOME TAXES | 42,866 | 28,594 | 60,898 | |||||||||
NET INCOME | $ | 58,007 | $ | 55,523 | $ | 88,033 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 243,220 | $ | 120 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $3,868 in 2010 and $4,044 in 2009 | 178,522 | 171,052 | ||||||
| Associated companies | 24,920 | 29,413 | ||||||
| Other | 13,007 | 11,650 | ||||||
| Notes receivable from associated companies | 11,028 | 97,150 | ||||||
| Prepaid taxes | 343 | 15,229 | ||||||
| Other | 2,289 | 1,459 | ||||||
| 473,329 | 326,073 | |||||||
UTILITY PLANT: | ||||||||
| In service | 2,247,853 | 2,162,815 | ||||||
| Less — Accumulated provision for depreciation | 846,003 | 810,746 | ||||||
| 1,401,850 | 1,352,069 | |||||||
| Construction work in progress | 23,663 | 14,901 | ||||||
| 1,425,513 | 1,366,970 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Nuclear plant decommissioning trusts | 289,328 | 266,479 | ||||||
| Other | 884 | 890 | ||||||
| 290,212 | 267,369 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 416,499 | 416,499 | ||||||
| Regulatory assets | 295,856 | 356,754 | ||||||
| Power purchase contract asset | 111,562 | 176,111 | ||||||
| Other | 31,699 | 36,544 | ||||||
| 855,616 | 985,908 | |||||||
| $ | 3,044,670 | $ | 2,946,320 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 28,760 | $ | 128,500 | ||||
| Short-term borrowings- | ||||||||
| Associated companies | 124,079 | — | ||||||
| Accounts payable- | ||||||||
| Associated companies | 33,942 | 40,521 | ||||||
| Other | 29,862 | 41,050 | ||||||
| Accrued taxes | 60,856 | 11,170 | ||||||
| Accrued interest | 16,114 | 17,362 | ||||||
| Other | 29,278 | 24,520 | ||||||
| 322,891 | 263,123 | |||||||
CAPITALIZATION (See Consolidated Statement of Capitalization): | ||||||||
| Common stockholder’s equity | 1,087,099 | 1,057,918 | ||||||
| Long-term debt and other long-term obligations | 718,860 | 713,873 | ||||||
| 1,805,959 | 1,771,791 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 473,009 | 453,462 | ||||||
| Accumulated deferred investment tax credits | 6,866 | 7,313 | ||||||
| Nuclear fuel disposal costs | 44,449 | 44,391 | ||||||
| Asset retirement obligations | 192,659 | 180,297 | ||||||
| Retirement benefits | 29,121 | 33,605 | ||||||
| Power purchase contract liability | 116,027 | 143,135 | ||||||
| Other | 53,689 | 49,203 | ||||||
| 915,820 | 911,406 | |||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 7 and 14) | ||||||||
| $ | 3,044,670 | $ | 2,946,320 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, without par value, 900,000 shares authorized, 859,500 shares outstanding | $ | 1,197,076 | $ | 1,197,070 | ||||
| Accumulated other comprehensive loss (Note 2(F)) | (142,383 | ) | (143,551 | ) | ||||
| Retained earnings (Note 11(A)) | 32,406 | 4,399 | ||||||
| Total | 1,087,099 | 1,057,918 | ||||||
LONG-TERM DEBT (Note 11(C)): | ||||||||
| First mortgage bonds- | ||||||||
| 5.950% due 2027 | 13,690 | 13,690 | ||||||
| Total | 13,690 | 13,690 | ||||||
| Unsecured notes- | ||||||||
| 4.450% due 2010 | — | 100,000 | ||||||
| 4.950% due 2013 | 150,000 | 150,000 | ||||||
| 4.875% due 2014 | 250,000 | 250,000 | ||||||
| 7.700% due 2019 | 300,000 | 300,000 | ||||||
| * 0.330% due 2021 | 28,500 | 28,500 | ||||||
| Total | 728,500 | 828,500 | ||||||
| Capital lease obligations (Note 7) | 5,158 | — | ||||||
| Unamortized premium on debt | 272 | 183 | ||||||
| Long-term debt due within one year | (28,760 | ) | (128,500 | ) | ||||
| Total long-term debt | 718,860 | 713,873 | ||||||
TOTAL CAPITALIZATION | $ | 1,805,959 | $ | 1,771,791 | ||||
| * | Denotes variable rate issue with applicable year-end interest rate shown. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | Retained | |||||||||||||||||||
| Common Stock | Other | Earnings | ||||||||||||||||||
| Comprehensive | Number | Carrying | Comprehensive | (Accumulated | ||||||||||||||||
| (Dollars in thousands) | Income (Loss) | of Shares | Value | Income (Loss) | Deficit) | |||||||||||||||
| Balance, January 1, 2008 | 859,500 | $ | 1,203,186 | $ | (15,397 | ) | $ | (139,157 | ) | |||||||||||
| Net income | $ | 88,033 | 88,033 | |||||||||||||||||
| Net unrealized gain on derivative instruments | 335 | 335 | ||||||||||||||||||
Pension and other postretirement benefits, net of $86,030 of income tax benefits (Note 3) | (125,922 | ) | (125,922 | ) | ||||||||||||||||
| Comprehensive loss | $ | (37,554 | ) | |||||||||||||||||
| Restricted stock units | 9 | |||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||
| Consolidated tax benefit allocation | 791 | |||||||||||||||||||
| Purchase accounting fair value adjustment | (7,815 | ) | ||||||||||||||||||
| Balance, December 31, 2008 | 859,500 | 1,196,172 | (140,984 | ) | (51,124 | ) | ||||||||||||||
| Net income | $ | 55,523 | 55,523 | |||||||||||||||||
| Net unrealized gain on derivative instruments | 335 | 335 | ||||||||||||||||||
Pension and other postretirement benefits, net of $2,784 of income taxes (Note 3) | (2,902 | ) | (2,902 | ) | ||||||||||||||||
| Comprehensive income | $ | 52,956 | ||||||||||||||||||
| Restricted stock units | 55 | |||||||||||||||||||
| Consolidated tax benefit allocation | 843 | |||||||||||||||||||
| Balance, December 31, 2009 | 859,500 | 1,197,070 | (143,551 | ) | 4,399 | |||||||||||||||
| Net income | $ | 58,007 | 58,007 | |||||||||||||||||
| Net unrealized loss on derivative instruments, net of $522 of income taxes | (187 | ) | (187 | ) | ||||||||||||||||
| Pension and other postretirement benefits, net of $1,066 of income tax benefits (Note 3) | 1,355 | 1,355 | ||||||||||||||||||
| Comprehensive income | $ | 59,175 | ||||||||||||||||||
| Restricted stock units | 6 | |||||||||||||||||||
| Cash dividends declared on common stock | (30,000 | ) | ||||||||||||||||||
| Balance, December 31, 2010 | 859,500 | $ | 1,197,076 | $ | (142,383 | ) | $ | 32,406 | ||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 58,007 | $ | 55,523 | $ | 88,033 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 52,176 | 51,006 | 44,556 | |||||||||
| Amortization of regulatory assets, net | 160,360 | 244,709 | 21,504 | |||||||||
| Deferred costs recoverable as regulatory assets | (62,462 | ) | (96,304 | ) | (25,132 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 29,528 | 66,965 | 49,939 | |||||||||
| Accrued compensation and retirement benefits | (2,474 | ) | 5,876 | (23,244 | ) | |||||||
| Cash collateral from (to) suppliers | 2,141 | (4,580 | ) | — | ||||||||
| Pension trust contribution | — | (123,521 | ) | — | ||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | (424 | ) | (32,088 | ) | (24,282 | ) | ||||||
| Prepayments and other current assets | 14,057 | (8,948 | ) | 8,223 | ||||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (18,598 | ) | (2,781 | ) | (12,512 | ) | ||||||
| Accrued taxes | 39,375 | (5,001 | ) | 470 | ||||||||
| Accrued interest | (1,248 | ) | 10,607 | (23 | ) | |||||||
| Other | 8,026 | 5,022 | 15,629 | |||||||||
| Net cash provided from operating activities | 278,464 | 166,485 | 143,161 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | — | 300,000 | 28,500 | |||||||||
| Short-term borrowings, net | 124,079 | — | — | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (100,000 | ) | — | (28,568 | ) | |||||||
| Short-term borrowings, net | — | (265,003 | ) | (20,324 | ) | |||||||
| Common stock dividend payments | (30,000 | ) | — | — | ||||||||
| Other | — | (2,268 | ) | (266 | ) | |||||||
| Net cash provided from (used for) financing activities | (5,921 | ) | 32,729 | (20,658 | ) | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (107,230 | ) | (100,201 | ) | (110,301 | ) | ||||||
| Sales of investment securities held in trusts | 460,277 | 67,973 | 181,007 | |||||||||
| Purchases of investment securities held in trusts | (470,192 | ) | (77,738 | ) | (193,061 | ) | ||||||
| Loans from (to) associated companies, net | 86,122 | (85,704 | ) | 1,128 | ||||||||
| Other, net | 1,580 | (3,568 | ) | (1,267 | ) | |||||||
| Net cash used for investing activities | (29,443 | ) | (199,238 | ) | (122,494 | ) | ||||||
| Net increase (decrease) in cash and cash equivalents | 243,100 | (24 | ) | 9 | ||||||||
| Cash and cash equivalents at beginning of year | 120 | 144 | 135 | |||||||||
| Cash and cash equivalents at end of year | $ | 243,220 | $ | 120 | $ | 144 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid (received) during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 49,285 | $ | 41,809 | $ | 38,627 | ||||||
| Income taxes | $ | (43,227 | ) | $ | (5,801 | ) | $ | 16,872 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
REVENUES: | ||||||||||||
| Electric sales | $ | 1,471,956 | $ | 1,385,574 | $ | 1,443,461 | ||||||
| Gross receipts tax collections | 67,915 | 63,372 | 70,168 | |||||||||
| Total revenues | 1,539,871 | 1,448,946 | 1,513,629 | |||||||||
EXPENSES (Note 17): | ||||||||||||
| Purchased power from affiliates | 643,152 | 341,645 | 284,074 | |||||||||
| Purchased power from non-affiliates | 364,647 | 544,490 | 591,487 | |||||||||
| Other operating costs | 268,614 | 209,156 | 228,257 | |||||||||
| Provision for depreciation | 61,141 | 61,317 | 54,643 | |||||||||
| Amortization (deferral) of regulatory assets, net | (34,819 | ) | 56,572 | 71,091 | ||||||||
| General taxes | 73,285 | 73,839 | 79,604 | |||||||||
| Total expenses | 1,376,020 | 1,287,019 | 1,309,156 | |||||||||
OPERATING INCOME | 163,851 | 161,927 | 204,473 | |||||||||
OTHER INCOME (EXPENSE): | ||||||||||||
| Miscellaneous income | 5,928 | 3,662 | 1,359 | |||||||||
| Interest expense (Note 17) | (69,864 | ) | (54,605 | ) | (59,424 | ) | ||||||
| Capitalized interest | 750 | 98 | (591 | ) | ||||||||
| Total other expense | (63,186 | ) | (50,845 | ) | (58,656 | ) | ||||||
INCOME BEFORE INCOME TAXES | 100,665 | 111,082 | 145,817 | |||||||||
INCOME TAXES | 41,173 | 45,694 | 57,647 | |||||||||
NET INCOME | $ | 59,492 | $ | 65,388 | $ | 88,170 | ||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
ASSETS | ||||||||
CURRENT ASSETS: | ||||||||
| Cash and cash equivalents | $ | 5 | $ | 14 | ||||
| Receivables- | ||||||||
| Customers, net of allowance for uncollectible accounts of $3,369 in 2010 and $3,483 in 2009 | 148,864 | 139,302 | ||||||
| Associated companies | 54,052 | 77,338 | ||||||
| Other | 11,314 | 18,320 | ||||||
| Notes receivable from associated companies | 14,404 | 14,589 | ||||||
| Prepaid taxes | 14,026 | 18,946 | ||||||
| Other | 1,592 | 1,400 | ||||||
| 244,257 | 269,909 | |||||||
UTILITY PLANT: | ||||||||
| In service | 2,532,629 | 2,431,737 | ||||||
| Less — Accumulated provision for depreciation | 935,259 | 901,990 | ||||||
| 1,597,370 | 1,529,747 | |||||||
| Construction work in progress | 30,505 | 24,205 | ||||||
| 1,627,875 | 1,553,952 | |||||||
OTHER PROPERTY AND INVESTMENTS: | ||||||||
| Nuclear plant decommissioning trusts | 152,928 | 142,603 | ||||||
| Non-utility generation trusts | 80,244 | 120,070 | ||||||
| Other | 297 | 289 | ||||||
| 233,469 | 262,962 | |||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||
| Goodwill | 768,628 | 768,628 | ||||||
| Regulatory assets | 163,407 | 9,045 | ||||||
| Power purchase contract asset | 5,746 | 15,362 | ||||||
| Other | 19,287 | 19,143 | ||||||
| 957,068 | 812,178 | |||||||
| $ | 3,062,669 | $ | 2,899,001 | |||||
LIABILITIES AND CAPITALIZATION | ||||||||
CURRENT LIABILITIES: | ||||||||
| Currently payable long-term debt | $ | 45,000 | $ | 69,310 | ||||
| Short-term borrowings- | ||||||||
| Associated companies | 101,338 | 41,473 | ||||||
| Accounts payable- | ||||||||
| Associated companies | 35,626 | 39,884 | ||||||
| Other | 41,420 | 41,990 | ||||||
| Accrued taxes | 5,075 | 6,409 | ||||||
| Accrued interest | 17,378 | 17,598 | ||||||
| Other | 22,541 | 22,741 | ||||||
| 268,378 | 239,405 | |||||||
CAPITALIZATION (See Consolidated Statement of Capitalization): | ||||||||
| Common stockholder’s equity | 899,538 | 931,386 | ||||||
| Long-term debt and other long-term obligations | 1,072,262 | 1,072,181 | ||||||
| 1,971,800 | 2,003,567 | |||||||
NONCURRENT LIABILITIES: | ||||||||
| Accumulated deferred income taxes | 371,877 | 242,040 | ||||||
| Retirement benefits | 187,621 | 174,306 | ||||||
| Asset retirement obligations | 98,132 | 91,841 | ||||||
| Power purchase contract liability | 116,972 | 100,849 | ||||||
| Other | 47,889 | 46,993 | ||||||
| 822,491 | 656,029 | |||||||
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 7 and 14) | ||||||||
| $ | 3,062,669 | $ | 2,899,001 | |||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CAPITALIZATION
| As of December 31, | ||||||||
| (Dollars in thousands) | 2010 | 2009 | ||||||
COMMON STOCKHOLDER’S EQUITY: | ||||||||
| Common stock, $20 par value, 5,400,000 shares authorized, 4,427,577 shares outstanding | $ | 88,552 | $ | 88,552 | ||||
| Other paid-in capital | 913,519 | 913,437 | ||||||
| Accumulated other comprehensive income (loss) (Note 2(F)) | (163,526 | ) | (162,104 | ) | ||||
| Retained earnings (Note 11(A)) | 60,993 | 91,501 | ||||||
| Total | 899,538 | 931,386 | ||||||
LONG-TERM DEBT (Note 11(C)): | ||||||||
| First mortgage bonds- | ||||||||
| 5.350% due 2010 | — | 12,310 | ||||||
| 5.350% due 2010 | — | 12,000 | ||||||
| Total | — | 24,310 | ||||||
| Unsecured notes- | ||||||||
| 5.125% due 2014 | 150,000 | 150,000 | ||||||
| 6.050% due 2017 | 300,000 | 300,000 | ||||||
| 6.625% due 2019 | 125,000 | 125,000 | ||||||
| *0.330% due 2020 | 20,000 | 20,000 | ||||||
| 5.200% due 2020 | 250,000 | 250,000 | ||||||
| *0.340% due 2025 | — | 25,000 | ||||||
| 2.250% due 2025 | 25,000 | — | ||||||
| 6.150% due 2038 | 250,000 | 250,000 | ||||||
| Total | 1,120,000 | 1,120,000 | ||||||
| Net unamortized discount on debt | (2,738 | ) | (2,819 | ) | ||||
| Long-term debt due within one year | (45,000 | ) | (69,310 | ) | ||||
| Total long-term debt | 1,072,262 | 1,072,181 | ||||||
TOTAL CAPITALIZATION | $ | 1,971,800 | $ | 2,003,567 | ||||
| * | Denotes variable rate issue with applicable year-end interest rate shown. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER’S EQUITY
| Accumulated | ||||||||||||||||||||||||
| Common Stock | Other | Other | ||||||||||||||||||||||
| Comprehensive | Number | Par | Paid-In | Comprehensive | Retained | |||||||||||||||||||
| (Dollars in thousands) | Income (Loss) | of Shares | Value | Capital | Income (Loss) | Earnings | ||||||||||||||||||
| Balance, January 1, 2008 | 4,427,577 | $ | 88,552 | $ | 920,616 | $ | 4,946 | $ | 57,943 | |||||||||||||||
| Net income | $ | 88,170 | 88,170 | |||||||||||||||||||||
| Net unrealized gain on investments, net of $13 of income taxes | 9 | 9 | ||||||||||||||||||||||
| Net unrealized gain on derivative instruments, net of $4 of income tax benefits | 69 | 69 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $90,822 of income tax benefits (Note 3) | (133,021 | ) | (133,021 | ) | ||||||||||||||||||||
| Comprehensive loss | $ | (44,773 | ) | |||||||||||||||||||||
| Restricted stock units | 35 | |||||||||||||||||||||||
| Stock-based compensation | 1 | |||||||||||||||||||||||
| Consolidated tax benefit allocation | 1,066 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (70,000 | ) | ||||||||||||||||||||||
| Purchase accounting fair value adjustment | (9,277 | ) | ||||||||||||||||||||||
| Balance, December 31, 2008 | 4,427,577 | 88,552 | 912,441 | (127,997 | ) | 76,113 | ||||||||||||||||||
| Net income | $ | 65,388 | 65,388 | |||||||||||||||||||||
| Change in unrealized gain on investments, net of $15 of income taxes | (2 | ) | (2 | ) | ||||||||||||||||||||
| Net unrealized gain on derivative instruments, net of $7 of income tax benefits | 72 | 72 | ||||||||||||||||||||||
| Pension and other postretirement benefits, net of $17,244 of income tax benefits (Note 3) | (34,177 | ) | (34,177 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 31,281 | ||||||||||||||||||||||
| Restricted stock units | 65 | |||||||||||||||||||||||
| Consolidated tax benefit allocation | 931 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (50,000 | ) | ||||||||||||||||||||||
| Balance, December 31, 2009 | 4,427,577 | 88,552 | 913,437 | (162,104 | ) | 91,501 | ||||||||||||||||||
| Net income | $ | 59,492 | 59,492 | |||||||||||||||||||||
| Net unrealized loss on derivative instruments, net of $105 of income taxes | (40 | ) | (40 | ) | ||||||||||||||||||||
| Pension and other postretirement benefits, net of $4,367 of income tax benefits (Note 3) | (1,382 | ) | (1,382 | ) | ||||||||||||||||||||
| Comprehensive income | $ | 58,070 | ||||||||||||||||||||||
| Restricted stock units | 82 | |||||||||||||||||||||||
| Cash dividends declared on common stock | (90,000 | ) | ||||||||||||||||||||||
| Balance, December 31, 2010 | 4,427,577 | $ | 88,552 | $ | 913,519 | $ | (163,526 | ) | $ | 60,993 | ||||||||||||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
| For the Years Ended December 31, | ||||||||||||
| (In thousands) | 2010 | 2009 | 2008 | |||||||||
CASH FLOWS FROM OPERATING ACTIVITIES: | ||||||||||||
| Net income | $ | 59,492 | $ | 65,388 | $ | 88,170 | ||||||
| Adjustments to reconcile net income to net cash from operating activities- | ||||||||||||
| Provision for depreciation | 61,141 | 61,317 | 54,643 | |||||||||
| Amortization (deferral) of regulatory assets, net | (34,819 | ) | 56,572 | 71,091 | ||||||||
| Deferred costs recoverable as regulatory assets | (89,070 | ) | (100,990 | ) | (35,898 | ) | ||||||
| Deferred income taxes and investment tax credits, net | 133,885 | 63,065 | 95,227 | |||||||||
| Accrued compensation and retirement benefits | 8,206 | 3,866 | (25,661 | ) | ||||||||
| Cash collateral paid, net | (3,980 | ) | — | — | ||||||||
| Pension trust contribution | — | (60,000 | ) | — | ||||||||
| Decrease (increase) in operating assets- | ||||||||||||
| Receivables | 24,687 | 22,891 | (74,338 | ) | ||||||||
| Prepayments and other current assets | 4,728 | (2,519 | ) | (16,313 | ) | |||||||
| Increase (decrease) in operating liabilities- | ||||||||||||
| Accounts payable | (5,128 | ) | 3,114 | (1,966 | ) | |||||||
| Accrued taxes | (10,089 | ) | (6,855 | ) | (2,181 | ) | ||||||
| Accrued interest | (220 | ) | 4,467 | (36 | ) | |||||||
| Other | 4,909 | 3,236 | 17,815 | |||||||||
| Net cash provided from operating activities | 153,742 | 113,552 | 170,553 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||
| New financing- | ||||||||||||
| Long-term debt | 25,000 | 498,583 | 45,000 | |||||||||
| Short-term borrowings, net | 59,865 | — | 66,509 | |||||||||
| Redemptions and repayments- | ||||||||||||
| Long-term debt | (49,310 | ) | (135,000 | ) | (45,556 | ) | ||||||
| Short-term borrowings, net | — | (239,929 | ) | — | ||||||||
| Common stock dividend payments | (90,000 | ) | (85,000 | ) | (90,000 | ) | ||||||
| Other | (48 | ) | (4,453 | ) | — | |||||||
| Net cash provided from (used for) financing activities | (54,493 | ) | 34,201 | (24,047 | ) | |||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||
| Property additions | (126,344 | ) | (124,262 | ) | (126,672 | ) | ||||||
| Loan repayments from associated companies, net | 185 | 244 | 1,480 | |||||||||
| Sales of investment securities held in trusts | 164,627 | 84,400 | 117,751 | |||||||||
| Purchases of investment securities held in trusts | (129,714 | ) | (98,467 | ) | (134,621 | ) | ||||||
| Other, net | (8,012 | ) | (9,677 | ) | (4,467 | ) | ||||||
| Net cash used for investing activities | (99,258 | ) | (147,762 | ) | (146,529 | ) | ||||||
| Net decrease in cash and cash equivalents | (9 | ) | (9 | ) | (23 | ) | ||||||
| Cash and cash equivalents at beginning of year | 14 | 23 | 46 | |||||||||
| Cash and cash equivalents at end of year | $ | 5 | $ | 14 | $ | 23 | ||||||
SUPPLEMENTAL CASH FLOW INFORMATION: | ||||||||||||
| Cash paid (received) during the year- | ||||||||||||
| Interest (net of amounts capitalized) | $ | 67,208 | $ | 48,265 | $ | 56,972 | ||||||
| Income taxes | $ | (115,870 | ) | $ | (10,775 | ) | $ | 44,197 | ||||
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
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COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, FERC and, as applicable, the PUCO, PPUC and NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation unless otherwise prescribed by GAAP (see Note 15). FirstEnergy consolidates a VIE (see Note 8) when it is determined to be the VIE’s primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) are accounted for under the equity method. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income. These footnotes combine results of FE, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.
Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) ACCOUNTING FOR THE EFFECTS OF REGULATION
FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to its operating utilities since their rates:
| • | are established by a third-party regulator with the authority to set rates that bind customers; |
| • | are cost-based; and |
| • | can be charged to and collected from customers. |
An enterprise meeting all of these criteria capitalizes costs that would otherwise be charged to expense (regulatory assets) if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Regulatory accounting is applied only to the parts of the business that meet the above criteria. If a portion of the business applying regulatory accounting no longer meets those requirements, previously recorded net regulatory assets are removed from the balance sheet in accordance with GAAP.
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Regulatory assets on the Balance Sheets are comprised of the following:
| Regulatory Assets | FE | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
December 31, 2010 | ||||||||||||||||||||||||||||
| Regulatory transition costs | $ | 770 | $ | — | $ | — | $ | — | $ | 591 | $ | 131 | $ | 43 | ||||||||||||||
| Customer shopping incentives | — | — | — | — | — | — | — | |||||||||||||||||||||
| Customer receivables for future income taxes | 326 | 50 | 2 | 1 | 30 | 113 | 130 | |||||||||||||||||||||
| Loss (gain) on reacquired debt | 48 | 17 | 1 | (3 | ) | 21 | 6 | 6 | ||||||||||||||||||||
| Employee postretirement benefits | 16 | — | 3 | 2 | 7 | 4 | — | |||||||||||||||||||||
| Nuclear decommissioning, decontamination and spent fuel disposal costs | (184 | ) | — | — | — | (31 | ) | (92 | ) | (61 | ) | |||||||||||||||||
| Asset removal costs | (237 | ) | (24 | ) | (47 | ) | (19 | ) | (147 | ) | — | — | ||||||||||||||||
| MISO/PJM transmission costs | 184 | (1 | ) | — | — | — | 131 | 52 | ||||||||||||||||||||
| Deferred generation costs | 386 | 125 | 226 | 35 | — | — | — | |||||||||||||||||||||
| Distribution costs | 426 | 216 | 155 | 55 | — | — | — | |||||||||||||||||||||
| Other | 91 | 17 | 30 | 1 | 42 | 3 | (7 | ) | ||||||||||||||||||||
| Total | $ | 1,826 | $ | 400 | $ | 370 | $ | 72 | $ | 513 | $ | 296 | $ | 163 | ||||||||||||||
December 31, 2009 | ||||||||||||||||||||||||||||
| Regulatory transition costs | $ | 1,100 | $ | 73 | $ | 8 | $ | 8 | $ | 965 | $ | 116 | $ | (70 | ) | |||||||||||||
| Customer shopping incentives | 154 | — | 154 | — | — | — | — | |||||||||||||||||||||
| Customer receivables for future income taxes | 329 | 58 | 3 | 1 | 31 | 114 | 122 | |||||||||||||||||||||
| Loss (gain) on reacquired debt | 51 | 18 | 1 | (3 | ) | 22 | 8 | 5 | ||||||||||||||||||||
| Employee postretirement benefits | 23 | — | 5 | 2 | 10 | 6 | — | |||||||||||||||||||||
| Nuclear decommissioning, decontamination and spent fuel disposal costs | (162 | ) | — | — | — | (22 | ) | (83 | ) | (57 | ) | |||||||||||||||||
| Asset removal costs | (231 | ) | (23 | ) | (43 | ) | (17 | ) | (148 | ) | — | — | ||||||||||||||||
| MISO/PJM transmission costs | 148 | (15 | ) | (15 | ) | (3 | ) | — | 187 | (6 | ) | |||||||||||||||||
| Deferred generation costs | 369 | 115 | 222 | 32 | — | — | — | |||||||||||||||||||||
| Distribution costs | 482 | 230 | 197 | 55 | — | — | — | |||||||||||||||||||||
| Other | 93 | 9 | 14 | (5 | ) | 30 | 9 | 15 | ||||||||||||||||||||
| Total | $ | 2,356 | $ | 465 | $ | 546 | $ | 70 | $ | 888 | $ | 357 | $ | 9 | ||||||||||||||
Regulatory assets that do not earn a current return totaled approximately $215 million as of December 31, 2010 (JCP&L — $38 million, Met-Ed — $131 million, Penelec — $12 million, OE — $18 million and, CEI — $16 million). Regulatory assets of JCP&L, Met-Ed and Penelec not earning a current return are primarily for certain regulatory transition costs and employee postretirement benefits and will be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. Regulatory assets of OE and CEI not earning a current return primarily relate to the deferral of certain purchased power costs for which the means of recovery as not yet been established by the PUCO.
Transition Cost Amortization
JCP&L’s and Met-Ed’s regulatory transition costs include the deferral of above-market costs for power supplied from NUGs of $164 million for JCP&L (recovered through NGC revenues) and $128 million for Met-Ed (recovered through CTC revenues). Projected above-market NUG costs are adjusted to fair value at the end of each quarter, with a corresponding offset to regulatory assets. Recovery of the remaining regulatory transition costs is expected to continue pursuant to various regulatory proceedings in New Jersey and Pennsylvania (see Note 10).
(B) REVENUES AND RECEIVABLES
The Utilities’ principal business is providing electric service to customers in Ohio, Pennsylvania and New Jersey. The Utilities’ retail customers are metered on a cycle basis. Electric revenues are recorded based on energy delivered through the end of the calendar month. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount receivable as revenue and reverse the related prior period estimate.
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Receivables from customers include distribution and retail electric sales to residential, commercial and industrial customers for the Utilities and retail and wholesale sales to customers for FES. There was no material concentration of receivables as of December 31, 2010 and 2009 with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2010 and 2009 are shown below.
| Customer Receivables | FE | FES | OE | CEI | TE(1) | JCP&L | Met-Ed | Penelec | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
December 31, 2010 | ||||||||||||||||||||||||||||||||
| Billed | $ | 752 | $ | 196 | $ | 81 | $ | 95 | $ | — | $ | 178 | $ | 101 | $ | 82 | ||||||||||||||||
| Unbilled | 640 | 170 | 96 | 89 | — | 145 | 78 | 67 | ||||||||||||||||||||||||
| Total | $ | 1,392 | $ | 366 | $ | 177 | $ | 184 | $ | — | $ | 323 | $ | 179 | $ | 149 | ||||||||||||||||
December 31, 2009 | ||||||||||||||||||||||||||||||||
| Billed | $ | 725 | $ | 109 | $ | 101 | $ | 114 | $ | 1 | $ | 183 | $ | 110 | $ | 88 | ||||||||||||||||
| Unbilled | 519 | 86 | 108 | 95 | — | 118 | 61 | 51 | ||||||||||||||||||||||||
| Total | $ | 1,244 | $ | 195 | $ | 209 | $ | 209 | $ | 1 | $ | 301 | $ | 171 | $ | 139 | ||||||||||||||||
| (1) | See Note 13 for a discussion of TE’s accounts receivable financing arrangement with Centerior Funding Corporation. |
(C) EARNINGS PER SHARE OF COMMON STOCK
Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
| Reconciliation of Basic and Diluted | ||||||||||||
| Earnings per Share of Common Stock | 2010 | 2009 | 2008 | |||||||||
| (In millions, except per share amounts) | ||||||||||||
| Earnings available to FirstEnergy Corp. | $ | 784 | $ | 1,006 | $ | 1,342 | ||||||
| Weighted average number of basic shares outstanding | 304 | 304 | 304 | |||||||||
| Assumed exercise of dilutive stock options and awards | 1 | 2 | 3 | |||||||||
| Weighted average number of diluted shares outstanding | 305 | 306 | 307 | |||||||||
| Basic earnings per share of common stock | $ | 2.58 | $ | 3.31 | $ | 4.41 | ||||||
| Diluted earnings per share of common stock | $ | 2.57 | $ | 3.29 | $ | 4.38 | ||||||
(D) PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment reflects original cost (except for nuclear generating assets which are adjusted to fair value), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances as of December 31, 2010 and 2009 were as follows:
| December 31, 2010 | December 31, 2009 | |||||||||||||||||||||||
| Property, Plant and Equipment | Unregulated | Regulated | Total | Unregulated | Regulated | Total | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| In service | $ | 11,952 | $ | 17,499 | $ | 29,451 | $ | 10,935 | $ | 16,891 | $ | 27,826 | ||||||||||||
| Less accumulated depreciation | (4,229 | ) | (6,951 | ) | (11,180 | ) | (4,699 | ) | (6,698 | ) | (11,397 | ) | ||||||||||||
| Net plant in service | $ | 7,723 | $ | 10,548 | $ | 18,271 | $ | 6,236 | $ | 10,193 | $ | 16,429 | ||||||||||||
FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite rates for FirstEnergy’s subsidiaries’ electric plant in 2010, 2009 and 2008 are shown in the following table:
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| Annual Composite | ||||||||||||
| Depreciation Rate | ||||||||||||
| 2010 | 2009 | 2008 | ||||||||||
| OE | 2.9 | % | 3.1 | % | 3.1 | % | ||||||
| CEI | 3.2 | 3.3 | 3.5 | |||||||||
| TE | 3.3 | 3.3 | 3.6 | |||||||||
| Penn | 2.2 | 2.4 | 2.4 | |||||||||
| JCP&L | 2.4 | 2.4 | 2.3 | |||||||||
| Met-Ed | 2.5 | 2.5 | 2.3 | |||||||||
| Penelec | 2.5 | 2.6 | 2.5 | |||||||||
| FGCO | 4.0 | 4.6 | 4.7 | |||||||||
| NGC | 3.1 | 3.0 | 2.8 | |||||||||
Asset Retirement Obligations
FirstEnergy recognizes an ARO for the future decommissioning of its nuclear power plants and future remediation of other environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy’s current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation ARO. This approach applies probability weighting to discounted future cash flow scenarios that reflect a range of possible outcomes. The scenarios consider settlement of the ARO at the expiration of the nuclear power plant’s current license, settlement based on an extended license term and expected remediation dates. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset, as described further in Note 12.
(E) ASSET IMPAIRMENTS
Long-lived Assets
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such an asset may not be recoverable. The recoverability of the long-lived asset is measured by comparing the long-lived asset’s carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted future cash flows of the long-lived asset, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. Impairments of long-lived assets recognized for the year ended December 31, 2010, are described further in Note 19.
Goodwill
In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. Goodwill is evaluated for impairment at least annually and more frequently if indicators of impairment arise. In accordance with the accounting standards, if the fair value of a reporting unit is less than its carrying value (including goodwill), the goodwill is tested for impairment. Impairment is indicated and a loss is recognized if the implied fair value of a reporting unit’s goodwill is less than the carrying value of its goodwill.
FirstEnergy’s goodwill primarily relates to its energy delivery services segment. FirstEnergy’s aggregated reporting units are consistent with its operating segments — energy delivery services and competitive energy. Goodwill is allocated to these operating segments based on the original purchase price allocation for acquisitions within the various reporting units. The goodwill allocated to competitive energy is insignificant to that segment and to FirstEnergy.
Annual impairment testing is conducted during the third quarter of each year and for 2010, 2009 and 2008 the analysis indicated no impairment of goodwill. For purposes of annual testing the estimated fair values of energy delivery services and the utilities were determined using a discounted cash flow approach.
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The discounted cash flow model of the reporting units, which are aggregated into operating segments, is based on the forecasted operating cash flow for the current year, projected operating cash flows for the next five years (determined using forecasted amounts as well as an estimated growth rate) and a terminal value beyond five years. Discounted cash flows consist of the operating cash flows for each reporting unit less an estimate for capital expenditures. The key assumptions incorporated in the discounted cash flow approach include growth rates, projected operating income, changes in working capital, projected capital expenditures, planned funding of pension plans, anticipated funding of nuclear decommissioning trusts, expected results of future rate proceedings and a discount rate equal to the assumed long term cost of capital. Cash flows may be adjusted to exclude certain non-recurring or unusual items. Reporting unit income, which excludes non-recurring or unusual items, was the starting point for determining operating cash flow and there were no non-recurring or unusual items excluded from the calculations of operating cash flow in any of the periods included in the determination of fair value.
Unanticipated changes in assumptions could have a significant effect on FirstEnergy’s evaluation of goodwill. At the time of annual impairment testing, fair value would have to have declined in excess of 52% for energy delivery services to indicate a potential goodwill impairment. Fair value would have to have declined more than 26% for CEI, 64% for TE, 38% for JCP&L, 56% for Met-Ed and 57% for Penelec to indicate potential goodwill impairment.
A summary of the changes in goodwill for the three years ended December 31, 2010 is shown below by operating segment, which represent aggregated reporting units (see Note 15):
| Energy | Competitive | |||||||||||
| Delivery | Energy | |||||||||||
| Goodwill | Services | Services | Consolidated | |||||||||
| (In millions) | ||||||||||||
| Balance as of December 31, 2007 | $ | 5,583 | $ | 24 | $ | 5,607 | ||||||
| Adjustments related to GPU acquisitions | (32 | ) | — | (32 | ) | |||||||
| Balance as of December 31, 2008, 2009 and 2010 | $ | 5,551 | $ | 24 | $ | 5,575 | ||||||
A summary of the changes in FES’ and the Utilities’ goodwill for the three years ended December 31, 2010 is shown below.
| Goodwill | FES | CEI | TE | JCP&L | Met-Ed | Penelec | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Balance as of December, 31 2007 | $ | 24 | $ | 1,689 | $ | 501 | $ | 1,826 | $ | 424 | $ | 778 | ||||||||||||
| Adjustments related to GPU acquisition | — | — | — | (15 | ) | (8 | ) | (9 | ) | |||||||||||||||
| Balance as of December, 31 2008, 2009 and 2010 | $ | 24 | $ | 1,689 | $ | 501 | $ | 1,811 | $ | 416 | $ | 769 | ||||||||||||
FirstEnergy, FES and the Utilities, with the exception of Met-Ed, have no accumulated impairment charge as of December 31, 2010. Met-Ed has an accumulated impairment charge of $355 million, which was recorded in 2006.
Investments
At the end of each reporting period, FirstEnergy evaluates its investments for impairment. Investments classified as available-for-sale securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold the investment until recovery and then considers, among other factors, the duration and the extent to which the security’s fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating investments for impairment. If the decline in fair value is determined to be other than temporary, the cost basis of the investment is written down to fair value. FirstEnergy recognizes in earnings the unrealized losses on available-for-sale securities held in its nuclear decommissioning trusts since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of other-than-temporary impairment. In 2010, 2009 and 2008, FirstEnergy recognized $33 million, $62 million and $123 million, respectively, of other-than-temporary impairments. The fair values of FirstEnergy’s investments are disclosed in Note 5(B).
(F) COMPREHENSIVE INCOME
Comprehensive income includes net income as reported on the Consolidated Statements of Income and all other changes in common stockholders’ equity except those resulting from transactions with stockholders and adjustments relating to noncontrolling interests. Accumulated other comprehensive income (loss), net of tax, included on FE’s, FES’ and the Utilities’ Consolidated Balance Sheets as of December 31, 2010 and 2009, is comprised of the following:
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| Accumulated Other Comprehensive | ||||||||||||||||||||||||||||||||
| Income (Loss) | FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Net liability for unfunded retirement benefits | $ | (1,492 | ) | $ | (127 | ) | $ | (180 | ) | $ | (153 | ) | $ | (49 | ) | $ | (253 | ) | $ | (141 | ) | $ | (164 | ) | ||||||||
| Unrealized gain on investments | 7 | 6 | 1 | — | — | — | — | — | ||||||||||||||||||||||||
| Unrealized gain (loss) on derivative hedges | (54 | ) | 1 | — | — | — | (1 | ) | (1 | ) | — | |||||||||||||||||||||
| AOCL Balance, December 31, 2010 | $ | (1,539 | ) | $ | (120 | ) | $ | (179 | ) | $ | (153 | ) | $ | (49 | ) | $ | (254 | ) | $ | (142 | ) | $ | (164 | ) | ||||||||
| Net liability for unfunded retirement benefits | $ | (1,341 | ) | $ | (91 | ) | $ | (164 | ) | $ | (138 | ) | $ | (50 | ) | $ | (242 | ) | $ | (143 | ) | $ | (162 | ) | ||||||||
| Unrealized gain on investments | 2 | 2 | — | — | — | — | — | — | ||||||||||||||||||||||||
| Unrealized loss on derivative hedges | (76 | ) | (14 | ) | — | — | — | (1 | ) | (1 | ) | — | ||||||||||||||||||||
| AOCL Balance, December 31, 2009 | $ | (1,415 | ) | $ | (103 | ) | $ | (164 | ) | $ | (138 | ) | $ | (50 | ) | $ | (243 | ) | $ | (144 | ) | $ | (162 | ) | ||||||||
Other comprehensive income (loss) reclassified to net income during the three years ended December 31, 2010, 2009 and 2008 was as follows:
| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
| Pension and other postretirement benefits | $ | (67 | ) | $ | (3 | ) | $ | 1 | $ | (13 | ) | $ | (3 | ) | $ | (16 | ) | $ | (9 | ) | $ | (7 | ) | |||||||||
| Gain on investments | 54 | 50 | 2 | — | 2 | — | — | — | ||||||||||||||||||||||||
| Loss on derivative hedges | (35 | ) | (24 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| (48 | ) | 23 | 3 | (13 | ) | (1 | ) | (16 | ) | (9 | ) | (7 | ) | |||||||||||||||||||
| Income taxes (benefits) related to reclassification to net income | (19 | ) | 8 | 1 | (5 | ) | — | (6 | ) | (4 | ) | (3 | ) | |||||||||||||||||||
| Reclassification to net income | $ | (29 | ) | $ | 15 | $ | 2 | $ | (8 | ) | $ | (1 | ) | $ | (10 | ) | $ | (5 | ) | $ | (4 | ) | ||||||||||
2009 | ||||||||||||||||||||||||||||||||
| Pension and other postretirement benefits | $ | (78 | ) | $ | (3 | ) | $ | (5 | ) | $ | (11 | ) | $ | (2 | ) | $ | (18 | ) | $ | (11 | ) | $ | (5 | ) | ||||||||
| Gain on investments | 157 | 139 | 10 | — | 7 | — | — | — | ||||||||||||||||||||||||
| Loss on derivative hedges | (67 | ) | (27 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| 12 | 109 | 5 | (11 | ) | 5 | (18 | ) | (11 | ) | (5 | ) | |||||||||||||||||||||
| Income taxes (benefits) related to reclassification to net income | 4 | 41 | 2 | (4 | ) | 2 | (8 | ) | (5 | ) | (2 | ) | ||||||||||||||||||||
| �� | ||||||||||||||||||||||||||||||||
| Reclassification to net income | $ | 8 | $ | 68 | $ | 3 | $ | (7 | ) | $ | 3 | $ | (10 | ) | $ | (6 | ) | $ | (3 | ) | ||||||||||||
2008 | ||||||||||||||||||||||||||||||||
| Pension and other postretirement benefits | $ | 80 | $ | 7 | $ | 16 | $ | 1 | $ | — | $ | 14 | $ | 9 | $ | 14 | ||||||||||||||||
| Gain on investments | 40 | 31 | 9 | — | 1 | — | — | — | ||||||||||||||||||||||||
| Loss on derivative hedges | (19 | ) | (3 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| 101 | 35 | 25 | 1 | 1 | 14 | 9 | 14 | |||||||||||||||||||||||||
| Income taxes related to reclassification to net income | 41 | 14 | 10 | — | — | 6 | 4 | 6 | ||||||||||||||||||||||||
| Reclassification to net income | $ | 60 | $ | 21 | $ | 15 | $ | 1 | $ | 1 | $ | 8 | $ | 5 | $ | 8 | ||||||||||||||||
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3. PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On September 2, 2009, the Utilities and ATSI made a combined $500 million voluntary contribution to their qualified pension plan. Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure its qualified pension plan as of August 31, 2009. FirstEnergy intends to voluntarily contribute $250 million to its pension plan in 2011.
FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing other postretirement benefits to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. During 2008, FirstEnergy amended the OPEB plan effective in 2010 to limit the monthly contribution for pre-1990 retirees. On June 2, 2009, FirstEnergy amended its health care benefits plan for all employees and retirees eligible to participate in that plan. The amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
Pension and OPEB costs are affected by employee demographics (including age, compensation levels, and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date.
In the third quarter of 2009, FirstEnergy incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to a liability created by the VERO offered by FirstEnergy to qualified employees. The special termination benefits of the VERO included additional health care coverage subsidies paid by FirstEnergy to those qualified employees who elected to retire. A total of 715 employees accepted the VERO.
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| Obligations and Funded Status | Pension Benefits | Other Benefits | ||||||||||||||
| As of December 31 | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (In millions) | ||||||||||||||||
Change in benefit obligation | ||||||||||||||||
| Benefit obligation as of January 1 | $ | 5,392 | $ | 4,700 | $ | 823 | $ | 1,189 | ||||||||
| Service cost | 99 | 91 | 10 | 12 | ||||||||||||
| Interest cost | 314 | 317 | 45 | 64 | ||||||||||||
| Plan participants’ contributions | — | — | 30 | 29 | ||||||||||||
| Plan amendments | 16 | 6 | — | (408 | ) | |||||||||||
| Special termination benefits | — | — | — | 13 | ||||||||||||
| Medicare retiree drug subsidy | — | — | 7 | 20 | ||||||||||||
| Actuarial (gain) loss | 343 | 648 | 56 | 23 | ||||||||||||
| Benefits paid | (306 | ) | (370 | ) | (110 | ) | (119 | ) | ||||||||
| Benefit obligation as of December 31 | $ | 5,858 | $ | 5,392 | $ | 861 | $ | 823 | ||||||||
Change in fair value of plan assets | ||||||||||||||||
| Fair value of plan assets as of January 1 | $ | 4,399 | $ | 3,752 | $ | 467 | $ | 440 | ||||||||
| Actual return on plan assets | 440 | 508 | 52 | 62 | ||||||||||||
| Company contributions | 11 | 509 | 59 | 55 | ||||||||||||
| Plan participants’ contributions | — | — | 30 | 29 | ||||||||||||
| Benefits paid | (306 | ) | (370 | ) | (110 | ) | (119 | ) | ||||||||
| Fair value of plan assets as of December 31 | $ | 4,544 | $ | 4,399 | $ | 498 | $ | 467 | ||||||||
Funded Status | ||||||||||||||||
| Qualified plan | $ | (1,076 | ) | $ | (787 | ) | ||||||||||
| Non-qualified plans | (238 | ) | (206 | ) | ||||||||||||
| Funded Status | $ | (1,314 | ) | $ | (993 | ) | $ | (363 | ) | $ | (356 | ) | ||||
Accumulated benefit obligation | $ | 5,469 | $ | 5,036 | ||||||||||||
Amounts Recognized on the Balance Sheet | ||||||||||||||||
| Current liabilities | $ | (11 | ) | $ | (10 | ) | $ | — | $ | — | ||||||
| Noncurrent liabilities | (1,303 | ) | (983 | ) | (363 | ) | (356 | ) | ||||||||
| Net liability as of December 31 | $ | (1,314 | ) | $ | (993 | ) | $ | (363 | ) | $ | (356 | ) | ||||
Amounts Recognized in | ||||||||||||||||
Accumulated Other Comprehensive Income | ||||||||||||||||
| Prior service cost (credit) | $ | 76 | $ | 67 | $ | (952 | ) | $ | (1,145 | ) | ||||||
| Actuarial loss | 2,554 | 2,486 | 718 | 756 | ||||||||||||
| Net amount recognized | $ | 2,630 | $ | 2,553 | $ | (234 | ) | $ | (389 | ) | ||||||
Assumptions Used to Determine Benefit | ||||||||||||||||
Obligations as of December 31 | ||||||||||||||||
| Discount rate | 5.50 | % | 6.00 | % | 5.00 | % | 5.75 | % | ||||||||
| Rate of compensation increase | 5.20 | % | 5.20 | % | ||||||||||||
Allocation of Plan Assets | ||||||||||||||||
As of December 31 | ||||||||||||||||
| Equity securities | 28 | % | 39 | % | 47 | % | 51 | % | ||||||||
| Bonds | 50 | 49 | 45 | 46 | ||||||||||||
| Absolute return strategies | 11 | — | 3 | — | ||||||||||||
| Real estate | 6 | 6 | 2 | 1 | ||||||||||||
| Private equities | 4 | 5 | 1 | 1 | ||||||||||||
| Cash | 1 | 1 | 2 | 1 | ||||||||||||
| Total | 100 | % | 100 | % | 100 | % | 100 | % | ||||||||
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| Estimated 2011 Amortization of | ||||||||
| Net Periodic Pension Cost from | Pension | Other | ||||||
| Accumulated Other Comprehensive Income | Benefits | Benefits | ||||||
| (In millions) | ||||||||
| Prior service cost (credit) | $ | 14 | $ | (193 | ) | |||
| Actuarial loss | $ | 194 | $ | 57 | ||||
| Pension Benefits | Other Benefits | |||||||||||||||||||||||
| Components of Net Periodic Benefit Costs | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| Service cost | $ | 99 | $ | 91 | $ | 87 | $ | 10 | $ | 12 | $ | 19 | ||||||||||||
| Interest cost | 314 | 317 | 299 | 45 | 64 | 74 | ||||||||||||||||||
| Expected return on plan assets | (361 | ) | (343 | ) | (463 | ) | (36 | ) | (36 | ) | (51 | ) | ||||||||||||
| Amortization of prior service cost | 13 | 13 | 13 | (193 | ) | (175 | ) | (149 | ) | |||||||||||||||
| Amortization of net actuarial loss | 187 | 179 | 8 | 60 | 61 | 47 | ||||||||||||||||||
| Net periodic cost | $ | 252 | $ | 257 | $ | (56 | ) | $ | (114 | ) | $ | (74 | ) | $ | (60 | ) | ||||||||
FES’ and the Utilities’ shares of the net pension and OPEB asset (liability) as of December 31, 2010 and 2009 are as follows:
| Pension Benefits | Other Benefits | |||||||||||||||
| Net Pension and OPEB Asset (Liability) | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (In millions) | ||||||||||||||||
| FES | $ | (488 | ) | $ | (361 | ) | $ | (36 | ) | $ | (19 | ) | ||||
| OE | 29 | 30 | (66 | ) | (74 | ) | ||||||||||
| CEI | (22 | ) | (13 | ) | (62 | ) | (59 | ) | ||||||||
| TE | (21 | ) | (15 | ) | (46 | ) | (47 | ) | ||||||||
| JCP&L | (106 | ) | (77 | ) | (70 | ) | (56 | ) | ||||||||
| Met-Ed | (6 | ) | 6 | (19 | ) | (28 | ) | |||||||||
| Penelec | (99 | ) | (79 | ) | (85 | ) | (84 | ) | ||||||||
FES’ and the Utilities’ shares of the net periodic pension and OPEB costs for the three years ended December 31, 2010 are as follows:
| Pension Benefits | Other Benefits | |||||||||||||||||||||||
| Net Periodic Pension and OPEB Costs | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||
| FES | $ | 84 | $ | 71 | $ | 15 | $ | (27 | ) | $ | (15 | ) | $ | (7 | ) | |||||||||
| OE | 15 | 23 | (26 | ) | (25 | ) | (14 | ) | (7 | ) | ||||||||||||||
| CEI | 20 | 17 | (5 | ) | (6 | ) | — | 2 | ||||||||||||||||
| TE | 7 | 6 | (3 | ) | (1 | ) | 2 | 4 | ||||||||||||||||
| JCP&L | 25 | 31 | (15 | ) | (7 | ) | (6 | ) | (16 | ) | ||||||||||||||
| Met-Ed | 10 | 18 | (10 | ) | (8 | ) | (4 | ) | (10 | ) | ||||||||||||||
| Penelec | 19 | 16 | (13 | ) | (9 | ) | (4 | ) | (13 | ) | ||||||||||||||
| Assumptions Used | ||||||||||||||||||||||||
| to Determine Net Periodic Benefit Cost | Pension Benefits | Other Benefits | ||||||||||||||||||||||
| for Years Ended December 31 | 2010 | 2009 | 2008 | 2010 | 2009 | 2008 | ||||||||||||||||||
| Weighted-average discount rate | 6.00 | % | 7.00 | % | 6.50 | % | 5.75 | % | 7.00 | % | 6.50 | % | ||||||||||||
| Expected long-term return on plan assets | 8.50 | % | 9.00 | % | 9.00 | % | 8.50 | % | 9.00 | % | 9.00 | % | ||||||||||||
| Rate of compensation increase | 5.20 | % | 5.20 | % | 5.20 | % | ||||||||||||||||||
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Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy defined by accounting guidance are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 assets include registered investment companies, common stocks, publicly traded real estate investment trusts and certain shorter duration, more liquid fixed income securities. Registered investment companies and common stocks are stated at fair value as quoted on a recognized securities exchange and are valued at the last reported sales price on the last business day of the plan year. Market values for real estate investment trusts and certain fixed income securities are based on daily quotes available on public exchanges as with other publicly traded equity and fixed income securities.
Level 2 — Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 investments include common collective trusts, certain real estate investment trusts, and fixed income assets. Common collective trusts are not available in an exchange and active market; however, the fair value is determined based on the underlying investments as traded in an exchange and active market.
Level 3 — Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value in addition to the use of independent appraisers’ estimates of fair value on a periodic basis typically determined quarterly but no less than annually. Assets in this category include private equity, limited partnership, certain real estate trusts and fixed income securities. The fixed income securities’ market values are based in part on quantitative models and on observing market value ascertained through timely trades for securities that are similar to the ones being valued.
As of December 31, 2010 and 2009, the pension investments measured at fair value were as follows:
| December 31, 2010 | Asset | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Allocation | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Cash and short-term securities | $ | — | $ | 72 | $ | — | $ | 72 | 1 | % | ||||||||||
| Equity investments | ||||||||||||||||||||
| Domestic | 342 | 189 | — | 531 | 12 | % | ||||||||||||||
| International | 118 | 615 | — | 733 | 16 | % | ||||||||||||||
| Fixed income | ||||||||||||||||||||
| Government bonds | — | 722 | — | 722 | 16 | % | ||||||||||||||
| Corporate bonds | — | 1,414 | — | 1,414 | 31 | % | ||||||||||||||
| Distressed debt | — | 97 | — | 97 | 2 | % | ||||||||||||||
| Mortgaged-backed securities (non-government) | — | 52 | — | 52 | 1 | % | ||||||||||||||
| Alternatives | ||||||||||||||||||||
| Hedge funds | — | 497 | — | 497 | 11 | % | ||||||||||||||
| Private equity funds | — | — | 119 | 119 | 4 | % | ||||||||||||||
| Real estate funds | 2 | — | 282 | 284 | 6 | % | ||||||||||||||
| $ | 462 | $ | 3,658 | $ | 401 | $ | 4,521 | 100 | % | |||||||||||
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| December 31, 2009 | Asset | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Allocation | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Cash and short-term securities | $ | — | $ | 337 | $ | — | $ | 337 | 7 | % | ||||||||||
| Equity investments | ||||||||||||||||||||
| Domestic | 447 | 790 | — | 1,237 | 28 | % | ||||||||||||||
| International | 131 | 204 | — | 335 | 8 | % | ||||||||||||||
| Mutual funds | 159 | — | — | 159 | 4 | % | ||||||||||||||
| Fixed income | ||||||||||||||||||||
| Government bonds | — | 254 | — | 254 | 6 | % | ||||||||||||||
| Corporate bonds | — | 1,580 | — | 1,580 | 35 | % | ||||||||||||||
| Distressed debt | — | 92 | — | 92 | 2 | % | ||||||||||||||
| Mortgaged-backed securities (non-government) | — | 2 | — | 2 | 1 | % | ||||||||||||||
| Alternatives | ||||||||||||||||||||
| Private equity funds | — | — | 137 | 137 | 3 | % | ||||||||||||||
| Real estate funds | 1 | 4 | 241 | 246 | 6 | % | ||||||||||||||
| $ | 738 | $ | 3,263 | $ | 378 | $ | 4,379 | 100 | % | |||||||||||
The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2010 and 2009:
| Private Equity | Real Estate | |||||||
| Funds | Funds | |||||||
| Balance as of January 1, 2009 | $ | 74 | $ | 342 | ||||
| Actual return on plan assets: | ||||||||
| Unrealized gains (losses) | 6 | (104 | ) | |||||
| Realized gains (losses) | 1 | (1 | ) | |||||
| Purchases, sales and settlements | 12 | 4 | ||||||
| Transfers in (out) | 44 | — | ||||||
| Balance as of December 31, 2009 | 137 | 241 | ||||||
| Actual return on plan assets: | ||||||||
| Unrealized gains | 1 | 45 | ||||||
| Realized gains (losses) | 11 | (3 | ) | |||||
| Purchases, sales and settlements | (28 | ) | (1 | ) | ||||
| Transfers in (out) | (2 | ) | — | |||||
| Balance at December 31, 2010 | $ | 119 | $ | 282 | ||||
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As of December 31, 2010 and 2009, the other postretirement benefit investments measured at fair value were as follows:
| December 31, 2010 | Asset | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Allocation | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Cash and short-term securities | $ | — | $ | 16 | $ | — | $ | 16 | 2 | % | ||||||||||
| Equity investment | ||||||||||||||||||||
| Domestic | 178 | 6 | — | 184 | 36 | % | ||||||||||||||
| International | 20 | 19 | — | 39 | 9 | % | ||||||||||||||
| Mutual funds | 7 | 2 | — | 9 | 2 | % | ||||||||||||||
| Fixed income | ||||||||||||||||||||
| U.S. treasuries | — | 27 | — | 27 | 5 | % | ||||||||||||||
| Government bonds | — | 143 | — | 143 | 28 | % | ||||||||||||||
| Corporate bonds | — | 55 | — | 55 | 10 | % | ||||||||||||||
| Distressed debt | — | 3 | — | 3 | 1 | % | ||||||||||||||
| Mortgage-backed securities (non-government) | — | 4 | — | 4 | 1 | % | ||||||||||||||
| Alternatives | ||||||||||||||||||||
| Hedge funds | — | 15 | — | 15 | 3 | % | ||||||||||||||
| Private equity funds | — | — | 3 | 3 | 1 | % | ||||||||||||||
| Real estate funds | — | — | 9 | 9 | 2 | % | ||||||||||||||
| $ | 205 | $ | 290 | $ | 12 | $ | 507 | 100 | % | |||||||||||
| December 31, 2009 | Asset | |||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | Allocation | ||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Cash and short-term securities | $ | — | $ | 19 | $ | — | $ | 19 | 4 | % | ||||||||||
| Equity investment | ||||||||||||||||||||
| Domestic | 180 | 23 | — | 203 | 43 | % | ||||||||||||||
| International | 15 | 6 | — | 21 | 4 | % | ||||||||||||||
| Mutual funds | 10 | 2 | — | 12 | 3 | % | ||||||||||||||
| Fixed income | ||||||||||||||||||||
| U.S. treasuries | — | 20 | — | 20 | 4 | % | ||||||||||||||
| Government bonds | — | 123 | — | 123 | 26 | % | ||||||||||||||
| Corporate bonds | — | 56 | — | 56 | 12 | % | ||||||||||||||
| Distressed debt | — | 3 | — | 3 | 1 | % | ||||||||||||||
| Mortgage-backed securities (non-government) | — | 3 | — | 3 | 1 | % | ||||||||||||||
| Alternatives | ||||||||||||||||||||
| Private equity funds | — | — | 4 | 4 | 1 | % | ||||||||||||||
| Real estate funds | — | — | 7 | 7 | 1 | % | ||||||||||||||
| $ | 205 | $ | 255 | $ | 11 | $ | 471 | 100 | % | |||||||||||
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The following table provides a reconciliation of changes in the fair value of postretirement benefit investments classified as Level 3 in the fair value hierarchy during 2010 and 2009:
| Private Equity | Real Estate | |||||||
| Funds | Funds | |||||||
| (in millions) | ||||||||
| Balance as of January 1, 2009 | $ | 2 | $ | 10 | ||||
| Actual return on plan assets: | ||||||||
| Unrealized gains (losses) | — | (3 | ) | |||||
| Realized gains (losses) | — | — | ||||||
| Purchases, sales and settlements | 1 | — | ||||||
| Transfers in (out) | 1 | — | ||||||
| Balance as of December 31, 2009 | 4 | 7 | ||||||
| Actual return on plan assets: | ||||||||
| Unrealized gains | — | — | ||||||
| Realized gains (losses) | — | 2 | ||||||
| Purchases, sales and settlements | (1 | ) | — | |||||
| Transfers in (out) | — | — | ||||||
| Balance at December 31, 2010 | $ | 3 | $ | 9 | ||||
In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and other postretirement benefit obligations. The assumed rates of return on pension plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy.
FirstEnergy generally employs a total return investment approach whereby a mix of equities and fixed income investments are used to maximize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements, and periodic asset/liability studies.
FirstEnergy’s target asset allocations for its pension and OPEB portfolio for 2010 and 2009 are shown in the following table:
| Target Asset | ||||||||
| Allocations | ||||||||
| 2010 | 2009 | |||||||
| Equities | 21 | % | 58 | % | ||||
| Fixed income | 50 | 30 | ||||||
| Absolute return strategies | 21 | — | ||||||
| Real estate | 6 | 8 | ||||||
| Private equity | 2 | 4 | ||||||
| Total | 100 | % | 100 | % | ||||
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| Assumed Health Care Cost Trend Rates | ||||||||
| As of December 31 | 2010 | 2009 | ||||||
| Health care cost trend rate assumed (pre/post-Medicare) | 8.0-9.0 | % | 8.5-10 | % | ||||
| Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) | 5 | % | 5 | % | ||||
| Year that the rate reaches the ultimate trend rate (pre/post-Medicare) | 2016-2018 | 2016-2018 | ||||||
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
| 1-Percentage- | 1-Percentage- | |||||||
| Point Increase | Point Decrease | |||||||
| (in millions) | ||||||||
| Effect on total of service and interest cost | $ | 2 | $ | (2 | ) | |||
| Effect on accumulated postretirement benefit obligation | $ | 22 | $ | (20 | ) | |||
Taking into account estimated employee future service, FirstEnergy expects to make the following pension benefit payments from plan assets and other benefit payments, net of the Medicare subsidy and participant contributions:
| Pension | Other | |||||||
| Benefits | Benefits | |||||||
| (in millions) | ||||||||
| 2011 | $ | 320 | $ | 88 | ||||
| 2012 | 332 | 76 | ||||||
| 2013 | 344 | 61 | ||||||
| 2014 | 367 | 63 | ||||||
| 2015 | 381 | 61 | ||||||
| Years 2016-2020 | 2,068 | 297 | ||||||
4. STOCK-BASED COMPENSATION PLANS
FirstEnergy has four stock-based compensation programs — LTIP, EDCP, ESOP and DCPD.
(A) LTIP
FirstEnergy’s LTIP includes four stock-based compensation programs — restricted stock, restricted stock units, stock options and performance shares.
Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to pay out in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. As of December 31, 2010, 7.2 million shares were available for future awards.
FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or distributed. Realized tax benefits during the years ended December 31, 2010, 2009 and 2008 were $11 million, $9 million and $43 million, respectively. The excess of the deductible amount over the recognized compensation cost is recorded in stockholders’ equity and reported as an other financing activity on the Consolidated Statements of Cash Flows.
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Restricted Stock and Restricted Stock Units
Eligible employees receive awards of FirstEnergy common stock or stock units subject to restrictions. Those restrictions lapse over a defined period of time or based on performance. Dividends are received on the restricted stock and are reinvested in additional shares. Restricted common stock grants under the LTIP were as follows:
| 2010 | 2009 | 2008 | ||||||||||
| Restricted common shares granted | 71,752 | 73,255 | 82,607 | |||||||||
| Weighted average market price | $ | 38.43 | $ | 43.68 | $ | 68.98 | ||||||
| Weighted average vesting period (years) | 4.74 | 4.42 | 5.03 | |||||||||
| Dividends restricted | Yes | Yes | Yes | |||||||||
Vesting activity for restricted common stock during 2010 was as follows (forfeitures were not material):
| Weighted | ||||||||
| Number | Average | |||||||
| of | Grant-Date | |||||||
| Restricted Stock | Shares | Fair Value | ||||||
| Nonvested as of January 1, 2010 | 648,293 | $ | 50.39 | |||||
| Nonvested as of December 31, 2010 | 475,914 | 51.26 | ||||||
| Granted in 2010 | 71,752 | 38.43 | ||||||
| Vested in 2010 | 292,152 | 38.75 | ||||||
FirstEnergy grants two types of restricted stock unit awards: discretionary-based and performance-based. With the discretionary-based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in each agreement. With the performance-based, FirstEnergy grants the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of restricted stock units set forth in the agreement subject to adjustment based on FirstEnergy’s stock performance.
| 2010 | 2009 | 2008 | ||||||||||
| Restricted common shares units granted | 511,418 | 533,399 | 450,683 | |||||||||
| Weighted average vesting period (years) | 3.00 | 3.00 | 3.14 | |||||||||
Vesting activity for restricted stock units during 2010 was as follows (forfeitures were not material):
| Weighted | ||||||||
| Number | Average | |||||||
| of | Grant-Date | |||||||
| Restricted Stock Units | Shares | Fair Value | ||||||
| Nonvested as of January 1, 2010 | 1,489,187 | $ | 54.81 | |||||
| Nonvested as of December 31, 2010 | 1,402,108 | 48.40 | ||||||
| Granted in 2010 | 511,418 | 37.13 | ||||||
| Vested in 2010 | 579,736 | 38.83 | ||||||
Compensation expense recognized in 2010, 2009 and 2008 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $22 million, $25 million and $29 million, respectively.
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Stock Options
Stock options were granted to eligible employees allowing them to purchase a specified number of common shares at a fixed grant price over a defined period of time. Stock option activities under FirstEnergy stock option programs during 2010 were as follows:
| Weighted | ||||||||
| Number | Average | |||||||
| of | Grant-Date | |||||||
| Stock Option Activities | Shares | Fair value | ||||||
| Balance, January 1, 2010 | 3,074,626 | $ | 34.69 | |||||
| (3,074,626 options exercisable) | ||||||||
| Options granted | — | — | ||||||
| Options exercised | 180,460 | 26.86 | ||||||
| Options forfeited | 5,100 | 21.61 | ||||||
| Balance, December 31, 2010 | 2,889,066 | $ | 35.18 | |||||
| (2,889,066 options exercisable) | ||||||||
Options outstanding and range of exercise price as of December 31, 2010 were as follows:
| Options Outstanding and Exercisable | ||||||||||||
| Weighted | ||||||||||||
| Range of | Average | Remaining | ||||||||||
| Exercise Prices | Shares | Exercise Price | Contractual Life | |||||||||
| $29.50-29.71 | 894,054 | $ | 29.66 | 1.77 | ||||||||
| $34.45-39.46 | 1,995,012 | $ | 37.66 | 2.67 | ||||||||
Total | 2,889,066 | $ | 35.18 | 2.39 | ||||||||
FirstEnergy reduced its use of stock options beginning in 2005 and increased its use of performance-based, restricted stock units. As a result, all unvested stock options vested in 2008. No compensation expense was recognized for stock options during 2010 and 2009, and compensation expense in 2008 was not material. Cash received from the exercise of stock options in 2010, 2009 and 2008 was $6 million, $7 million and $74 million, respectively.
Performance Shares
Performance shares are share equivalents and do not have voting rights. The shares track the performance of FirstEnergy’s common stock over a three-year vesting period. During that time, dividend equivalents are converted into additional shares. The final account value may be adjusted based on the ranking of FirstEnergy stock performance to a composite of peer companies. Compensation expense (income) recognized for performance shares during 2010, 2009 and 2008, net of amounts capitalized, totaled approximately ($4) million, $3 million and $8 million, respectively. During 2010, no cash was paid to settle performance shares due to certain criteria not being met for the previous three-year vesting period. Cash used to settle performance shares in 2009 and 2008 was $15 million and $14 million, respectively.
(B) ESOP
An ESOP Trust funded most of the matching contribution for FirstEnergy’s 401(k) savings plan through December 31, 2007. All employees eligible for participation in the 401(k) savings plan are covered by the ESOP.
In 2008 and 2009, shares of FirstEnergy common stock were purchased on the market and contributed to participants’ accounts. Total ESOP-related compensation expenses in 2010, 2009 and 2008, net of amounts capitalized and dividends on common stock were $30 million, $36 million and $40 million, respectively.
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(C) EDCP
Under the EDCP, covered employees can direct a portion of their compensation, including annual incentive awards and/or long-term incentive awards, into an unfunded FirstEnergy stock account to receive vested stock units or into an unfunded retirement cash account. Through December 31, 2010, covered employees received an additional 20% premium in the form of stock units based on the amount allocated to the FirstEnergy stock account. During 2010, the EDCP was amended to cease the 20% stock premium with respect to annual and long-term incentive awards earned during any calendar years that commence on or after January 1, 2011. Dividends are calculated quarterly on stock units outstanding and are paid in the form of additional stock units. Upon withdrawal, stock units are converted to FirstEnergy shares. Payout typically occurs three years from the date of deferral; however, an election can be made in the year prior to payout to further defer shares into a retirement stock account that will pay out in cash upon retirement (see Note 3). Interest is calculated on the cash allocated to the cash account and the total balance will pay out in cash upon retirement. Compensation expense (income) recognized on EDCP stock units, net of amounts capitalized, in 2010, 2009 and 2008 was ($3) million, ($0.2) million and ($13) million, respectively.
(D) DCPD
Under the DCPD, directors can elect to allocate all or a portion of their cash retainers, meeting fees and chair fees to deferred stock or deferred cash accounts. Funds deferred into the stock account through December 31, 2010, receive a 20% match to the funds allocated. The 20% match and any appreciation on it are forfeited if the director leaves the Board within three years from the date of deferral for any reason other than retirement, disability, death, upon a change in control or when a director is ineligible to stand for re-election. Compensation expense is recognized for the 20% match over the three-year vesting period. Directors may also elect to defer their equity retainers into the deferred stock account; however, they do not receive a 20% match on that deferral. During 2010, the DCPD was amended to cease the 20% match feature with respect to director’s fees earned for service performed during any calendar years that commence on or after January 1, 2011. DCPD expenses recognized in 2010, 2009 and 2008 was $4 million, $3 million and $3 million, respectively. The net liability recognized for DCPD of approximately $5 million as of December 31, 2010, 2009 and 2008 is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.
Of the 1.7 million stock units authorized under the EDCP and DCPD, 1,239,415 stock units were available for future awards as of December 31, 2010.
5. FAIR VALUE OF FINANCIAL INSTRUMENTS
(A) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption “short-term borrowings.” The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of December 31, 2010 and 2009:
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Carrying | Fair | Carrying | Fair | |||||||||||||
| Value | Value | Value | Value | |||||||||||||
| (In millions) | ||||||||||||||||
| FirstEnergy (Consolidated) | $ | 13,928 | $ | 14,845 | $ | 13,853 | $ | 14,602 | ||||||||
| FES | 4,279 | 4,403 | 4,324 | 4,406 | ||||||||||||
| OE | 1,159 | 1,321 | 1,169 | 1,299 | ||||||||||||
| CEI | 1,853 | 2,035 | 1,873 | 2,032 | ||||||||||||
| TE | 600 | 653 | 600 | 638 | ||||||||||||
| JCP&L | 1,810 | 1,962 | 1,840 | 1,950 | ||||||||||||
| Met-Ed | 742 | 821 | 842 | 909 | ||||||||||||
| Penelec | 1,120 | 1,189 | 1,144 | 1,177 | ||||||||||||
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES and the Utilities.
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(B) INVESTMENTS
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities, available-for-sale securities and notes receivable.
FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security’s fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.
Available-For-Sale Securities
FES and the Utilities hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale at fair market value. FES and the Utilities have no securities held for trading purposes.
The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts as of December 31, 2010 and 2009:
| December 31, 2010(1) | December 31, 2009(2) | |||||||||||||||||||||||||||||||
| Cost | Unrealized | Unrealized | Fair | Cost | Unrealized | Unrealized | Fair | |||||||||||||||||||||||||
| Basis | Gains | Losses | Value | Basis | Gains | Losses | Value | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
Debt securities | ||||||||||||||||||||||||||||||||
| FirstEnergy | $ | 1,699 | $ | 31 | $ | — | $ | 1,730 | $ | 1,727 | $ | 22 | $ | — | $ | 1,749 | ||||||||||||||||
| FES | 980 | 13 | — | 993 | 1,043 | 3 | — | 1,046 | ||||||||||||||||||||||||
| OE | 123 | 1 | — | 124 | 55 | — | — | 55 | ||||||||||||||||||||||||
| TE | 42 | — | — | 42 | 72 | — | — | 72 | ||||||||||||||||||||||||
| JCP&L | 281 | 9 | — | 290 | 271 | 9 | — | 280 | ||||||||||||||||||||||||
| Met-Ed | 127 | 4 | — | 131 | 120 | 5 | — | 125 | ||||||||||||||||||||||||
| Penelec | 145 | 4 | — | 149 | 166 | 5 | — | 171 | ||||||||||||||||||||||||
Equity securities | ||||||||||||||||||||||||||||||||
| FirstEnergy | $ | 268 | $ | 69 | $ | — | $ | 337 | $ | 252 | $ | 43 | $ | — | $ | 295 | ||||||||||||||||
| JCP&L | 80 | 17 | — | 97 | 74 | 11 | — | 85 | ||||||||||||||||||||||||
| Met-Ed | 125 | 35 | — | 160 | 117 | 23 | — | 140 | ||||||||||||||||||||||||
| Penelec | 63 | 16 | — | 79 | 61 | 9 | — | 70 | ||||||||||||||||||||||||
| (1) | Excludes cash balances: FirstEnergy — $193 million; FES — $153 million; OE — $3 million; TE — $34 million; JCP&L — $3 million; Met-Ed — $(3) million and Penelec — $4 million. | |
| (2) | Excludes cash balances: FirstEnergy — $137 million; FES — $43 million; OE — $66 million; TE — $2 million; JCP&L — $3 million and Penelec — $23 million. |
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Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the three years ended December 31, 2010, 2009 and 2008 were as follows:
| Interest and | ||||||||||||||||
| December 31, 2010 | Sales Proceeds | Realized Gains | Realized Losses | Dividend Income | ||||||||||||
| (In millions) | ||||||||||||||||
| FirstEnergy | $ | 3,172 | $ | 126 | $ | 107 | $ | 79 | ||||||||
| FES | 1,927 | 92 | 75 | 47 | ||||||||||||
| OE | 83 | 2 | — | 3 | ||||||||||||
| TE | 126 | 3 | 1 | 2 | ||||||||||||
| JCP&L | 411 | 10 | 10 | 14 | ||||||||||||
| Met-Ed | 460 | 13 | 14 | 7 | ||||||||||||
| Penelec | 165 | 6 | 7 | 6 | ||||||||||||
| Interest and | ||||||||||||||||
| December 31, 2009 | Sales Proceeds | Realized Gains | Realized Losses | Dividend Income | ||||||||||||
| (In millions) | ||||||||||||||||
| FirstEnergy | $ | 2,229 | $ | 226 | $ | 155 | $ | 60 | ||||||||
| FES | 1,379 | 199 | 117 | 27 | ||||||||||||
| OE | 132 | 11 | 4 | 4 | ||||||||||||
| TE | 169 | 7 | 1 | 2 | ||||||||||||
| JCP&L | 397 | 6 | 12 | 14 | ||||||||||||
| Met-Ed | 68 | 2 | 13 | 7 | ||||||||||||
| Penelec | 84 | 1 | 8 | 6 | ||||||||||||
| Interest and | ||||||||||||||||
| December 31, 2008 | Sales Proceeds | Realized Gains | Realized Losses | Dividend Income | ||||||||||||
| (In millions) | ||||||||||||||||
| FirstEnergy | $ | 1,657 | $ | 115 | $ | 237 | $ | 76 | ||||||||
| FES | 951 | 99 | 184 | 37 | ||||||||||||
| OE | 121 | 11 | 9 | 5 | ||||||||||||
| TE | 38 | 1 | — | 3 | ||||||||||||
| JCP&L | 248 | 1 | 17 | 14 | ||||||||||||
| Met-Ed | 181 | 2 | 17 | 9 | ||||||||||||
| Penelec | 118 | 1 | 10 | 8 | ||||||||||||
Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI since fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund’s custodian or managers and their parents or subsidiaries.
During 2010, 2009 and 2008, FirstEnergy recognized $55 million, $176 million and $63 million of net realized gains resulting from the sale of securities held in nuclear decommissioning trusts.
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Held-To-Maturity Securities
The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of December 31, 2010 and 2009:
| December 31, 2010 | December 31, 2009 | |||||||||||||||||||||||||||||||
| Cost | Unrealized | Unrealized | Fair | Cost | Unrealized | Unrealized | Fair | |||||||||||||||||||||||||
| Basis | Gains | Losses | Value | Basis | Gains | Losses | Value | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
Debt Securities | ||||||||||||||||||||||||||||||||
| FirstEnergy | $ | 476 | $ | 91 | $ | — | $ | 567 | $ | 544 | $ | 72 | $ | — | $ | 616 | ||||||||||||||||
| OE | 190 | 51 | — | 241 | 217 | 29 | — | 246 | ||||||||||||||||||||||||
| CEI | 340 | 41 | — | 381 | 389 | 43 | — | 432 | ||||||||||||||||||||||||
Investments in emission allowances, employee benefits and cost and equity method investments totaling $259 million as of December 31, 2010, and $264 million as of December 31, 2009, are not required to be disclosed and are excluded from the amounts reported above.
Notes Receivable
The table below provides the approximate fair value and related carrying amounts of notes receivable as of December 31, 2010 and 2009. The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2013 to 2021.
| December 31, 2010 | December 31, 2009 | |||||||||||||||
| Carrying | Fair | Carrying | Fair | |||||||||||||
| Value | Value | Value | Value | |||||||||||||
| (In millions) | ||||||||||||||||
Notes Receivable | ||||||||||||||||
| FirstEnergy | $ | 7 | $ | 8 | $ | 36 | $ | 35 | ||||||||
| FES | — | — | 2 | 1 | ||||||||||||
| TE | 104 | 118 | 124 | 141 | ||||||||||||
(C) RECURRING FAIR VALUE MEASUREMENTS
Fair value is the price that would be received for an asset or paid to transfer a liability (exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between willing market participants on the measurement date. A fair value hierarchy has been established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). The three levels of the fair value hierarchy are as follows:
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those where transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. FirstEnergy’s Level 1 assets and liabilities primarily consist of exchange-traded derivatives and equity securities listed on active exchanges that are held in various trusts.
Level 2 — Pricing inputs are either directly or indirectly observable in the market as of the reporting date, other than quoted prices in active markets included in Level 1. FirstEnergy’s Level 2 assets and liabilities consist primarily of investments in debt securities held in various trusts and commodity forwards. Additionally, Level 2 includes those financial instruments that are valued using models or other valuation methodologies based on assumptions that are observable in the marketplace throughout the full term of the instrument and can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Instruments in this category may include non-exchange-traded derivatives such as forwards and certain interest rate swaps.
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Level 3 — Pricing inputs include inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. FirstEnergy develops its view of the future market price of key commodities through a combination of market observation and assessment (generally for the short term) and fundamental modeling (generally for the long term). Key fundamental electricity model inputs are generally directly observable in the market or derived from publicly available historic and forecast data. Some key inputs reflect forecasts published by industry leading consultants who generally employ similar fundamental modeling approaches. Fundamental model inputs and results, as well as the selection of consultants, reflect the consensus of appropriate FirstEnergy management. Level 3 instruments include those that may be more structured or otherwise tailored to customers’ needs. FirstEnergy’s Level 3 instruments consist exclusively of NUG contracts.
FirstEnergy utilizes market data and assumptions that market participants would use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation technique. These inputs can be readily observable, market corroborated, or generally unobservable. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs.
The determination of the fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of December 31, 2010 and 2009. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels. Transfers between levels are recognized at the end of the reporting period. During 2010, there were no significant transfers between Level 1, Level 2 and Level 3.
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FirstEnergy Corp.
The following tables provide the fair value measurement amounts for assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value at December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 597 | $ | — | $ | 597 | ||||||||
| Derivative assets — commodity contracts | — | 250 | — | 250 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 122 | 122 | ||||||||||||
Equity securities(2) | 338 | — | — | 338 | ||||||||||||
| Foreign government debt securities | — | 149 | — | 149 | ||||||||||||
| U.S. government debt securities | — | 595 | — | 595 | ||||||||||||
| U.S. state debt securities | — | 379 | — | 379 | ||||||||||||
Other(4) | — | 219 | — | 219 | ||||||||||||
Total assets | $ | 338 | $ | 2,189 | $ | 122 | $ | 2,649 | ||||||||
Liabilities | ||||||||||||||||
| Derivative liabilities — commodity contracts | $ | — | $ | (348 | ) | $ | — | $ | (348 | ) | ||||||
Derivative liabilities — NUG contracts(1) | — | — | (466 | ) | (466 | ) | ||||||||||
Total liabilities | $ | — | $ | (348 | ) | $ | (466 | ) | $ | (814 | ) | |||||
Net assets (liabilities)(3) | $ | 338 | $ | 1,841 | $ | (344 | ) | $ | 1,835 | |||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 484 | $ | — | $ | 484 | ||||||||
| Derivative assets — commodity contracts | — | 34 | — | 34 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 200 | 200 | ||||||||||||
Equity securities(2) | 295 | — | — | 295 | ||||||||||||
| Foreign government debt securities | — | 279 | — | 279 | ||||||||||||
| U.S. government debt securities | — | 558 | — | 558 | ||||||||||||
| U.S. state debt securities | — | 478 | — | 478 | ||||||||||||
Other(4) | — | 75 | — | 75 | ||||||||||||
Total assets | $ | 295 | $ | 1,908 | $ | 200 | $ | 2,403 | ||||||||
Liabilities | ||||||||||||||||
| Derivative liabilities — commodity contracts | $ | (11 | ) | $ | (224 | ) | $ | — | $ | (235 | ) | |||||
Derivative liabilities — NUG contracts(1) | — | — | (643 | ) | (643 | ) | ||||||||||
Total liabilities | $ | (11 | ) | $ | (224 | ) | $ | (643 | ) | $ | (878 | ) | ||||
Net assets (liabilities)(3) | $ | 284 | $ | 1,684 | $ | (443 | ) | $ | 1,525 | |||||||
| (1) | NUG contracts are subject to regulatory accounting and do not impact earnings. | |
| (2) | NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index. | |
| (3) | Excludes $(7) million and $21 million as of December 31, 2010 and 2009, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. | |
| (4) | Primarily consists of cash and cash equivalents. |
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Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2010 and 2009:
| Derivative Asset | Derivative Liability | Net | ||||||||||
| NUG Contracts(1) | NUG Contracts(1) | NUG Contracts(1) | ||||||||||
| (In millions) | ||||||||||||
| January 1, 2010 Balance | $ | 200 | $ | (643 | ) | $ | (443 | ) | ||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (71 | ) | (110 | ) | (181 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | (7 | ) | 287 | 280 | ||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2010 Balance | $ | 122 | $ | (466 | ) | $ | (344 | ) | ||||
| January 1, 2009 Balance | $ | 434 | $ | (765 | ) | $ | (331 | ) | ||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (234 | ) | (236 | ) | (470 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | — | 358 | 358 | |||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2009 Balance | $ | 200 | $ | (643 | ) | $ | (443 | ) | ||||
| (1) | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
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FirstEnergy Solutions Corp.
The following tables provide the fair value measurement amounts for assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 528 | $ | — | $ | 528 | ||||||||
| Derivative assets — commodity contracts | — | 241 | — | 241 | ||||||||||||
| Foreign government debt securities | — | 147 | — | 147 | ||||||||||||
| U.S. government debt securities | — | 308 | — | 308 | ||||||||||||
| U.S. state debt securities | — | 6 | — | 6 | ||||||||||||
Other(2) | — | 148 | — | 148 | ||||||||||||
Total assets | $ | — | $ | 1,378 | $ | — | $ | 1,378 | ||||||||
Liabilities | ||||||||||||||||
| Derivative liabilities — commodity contracts | $ | — | $ | (348 | ) | $ | — | $ | (348 | ) | ||||||
Total liabilities | $ | — | $ | (348 | ) | $ | — | $ | (348 | ) | ||||||
Net assets (liabilities)(1) | $ | — | $ | 1,030 | $ | — | $ | 1,030 | ||||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 443 | $ | — | $ | 443 | ||||||||
| Derivative assets — commodity contracts | — | 15 | — | 15 | ||||||||||||
| Foreign government debt securities | — | 279 | — | 279 | ||||||||||||
| U.S. government debt securities | — | 306 | 306 | |||||||||||||
| U.S. state debt securities | — | 15 | — | 15 | ||||||||||||
Other(2) | — | 29 | — | 29 | ||||||||||||
Total assets | $ | — | $ | 1,087 | $ | — | $ | 1,087 | ||||||||
Liabilities | ||||||||||||||||
| Derivative liabilities — commodity contracts | $ | (11 | ) | $ | (224 | ) | $ | — | $ | (235 | ) | |||||
Total liabilities | $ | (11 | ) | $ | (224 | ) | $ | — | $ | (235 | ) | |||||
Net assets (liabilities)(1) | $ | (11 | ) | $ | 863 | $ | — | $ | 852 | |||||||
| (1) | Excludes $7 million and $15 million as of December 31, 2010 and 2009, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. | |
| (2) | Primarily consists of cash and cash equivalents. |
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Ohio Edison Company
The following tables provide the fair value measurement amounts for assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| U.S. government debt securities | $ | — | $ | 124 | $ | — | $ | 124 | ||||||||
| Other | — | 2 | — | 2 | ||||||||||||
Total assets(1) | $ | — | $ | 126 | $ | — | $ | 126 | ||||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| U.S. government debt securities | $ | — | $ | 118 | $ | — | $ | 118 | ||||||||
| Other | — | 2 | — | 2 | ||||||||||||
Total assets(1) | $ | — | $ | 120 | $ | — | $ | 120 | ||||||||
| (1) | Excludes $1 million as of December 31, 2010 and 2009 of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
Toledo Edison Company
The following tables provide the fair value measurement amounts for assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 7 | $ | — | $ | 7 | ||||||||
| U.S. government debt securities | — | 33 | — | 33 | ||||||||||||
| U.S. state debt securities | — | 1 | — | 1 | ||||||||||||
Other(2) | — | 35 | — | 35 | ||||||||||||
Total assets(1) | $ | — | $ | 76 | $ | — | $ | 76 | ||||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | — | $ | — | $ | — | ||||||||
| U.S. government debt securities | — | 72 | — | 72 | ||||||||||||
| Other | — | — | — | — | ||||||||||||
Total assets(1) | $ | — | $ | 72 | $ | — | $ | 72 | ||||||||
| (1) | Excludes $2 million as of December 31, 2009 of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. | |
| (2) | Primarily consists of cash and cash equivalents. |
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Jersey Central Power & Light Company
The following tables provide the fair value measurement amounts for assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 23 | $ | — | $ | 23 | ||||||||
| Derivative assets — commodity contracts | — | 2 | — | 2 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 6 | 6 | ||||||||||||
Equity securities(2) | 96 | — | — | 96 | ||||||||||||
| U.S. government debt securities | — | 33 | — | 33 | ||||||||||||
| U.S. state debt securities | — | 236 | — | 236 | ||||||||||||
| Other | — | 4 | — | 4 | ||||||||||||
Total assets | $ | 96 | $ | 298 | $ | 6 | $ | 400 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (233 | ) | $ | (233 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (233 | ) | $ | (233 | ) | ||||||
Net assets (liabilities)(3) | $ | 96 | $ | 298 | $ | (227 | ) | $ | 167 | |||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 15 | $ | — | $ | 15 | ||||||||
| Derivative assets — commodity contracts | — | 5 | — | 5 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 8 | 8 | ||||||||||||
Equity securities(2) | 87 | — | — | 87 | ||||||||||||
| U.S. government debt securities | — | 23 | — | 23 | ||||||||||||
| U.S. state debt securities | — | 230 | — | 230 | ||||||||||||
| Other | — | 12 | — | 12 | ||||||||||||
Total assets | $ | 87 | $ | 285 | $ | 8 | $ | 380 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (399 | ) | $ | (399 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (399 | ) | $ | (399 | ) | ||||||
Net assets (liabilities)(3) | $ | 87 | $ | 285 | $ | (391 | ) | $ | (19 | ) | ||||||
| (1) | NUG contracts are subject to regulatory accounting and do not impact earnings. | |
| (2) | NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index. | |
| (3) | Excludes $(3) million as of December 31, 2010 of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
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Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2010 and 2009:
| Derivative Asset | Derivative Liability | Net | ||||||||||
| NUG Contracts(1) | NUG Contracts(1) | NUG Contracts(1) | ||||||||||
| (In millions) | ||||||||||||
| January 1, 2010 Balance | $ | 8 | $ | (399 | ) | $ | (391 | ) | ||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (1 | ) | 36 | 35 | ||||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | (1 | ) | 130 | 129 | ||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2010 Balance | $ | 6 | $ | (233 | ) | $ | (227 | ) | ||||
| January 1, 2009 Balance | $ | 14 | $ | (531 | ) | $ | (517 | ) | ||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (6 | ) | (36 | ) | (42 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | — | 168 | 168 | |||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2009 Balance | $ | 8 | $ | (399 | ) | $ | (391 | ) | ||||
| (1) | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
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Metropolitan Edison Company
The following tables provide the fair value measurement amounts for assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 32 | $ | — | $ | 32 | ||||||||
| Derivative assets — commodity contracts | — | 5 | — | 5 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 112 | 112 | ||||||||||||
Equity securities(2) | 160 | — | — | 160 | ||||||||||||
| Foreign government debt securities | — | 1 | — | 1 | ||||||||||||
| U.S. government debt securities | — | 88 | — | 88 | ||||||||||||
| U.S. state debt securities | — | 2 | — | 2 | ||||||||||||
| Other | — | 14 | — | 14 | ||||||||||||
Total assets | $ | 160 | $ | 142 | $ | 112 | $ | 414 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (116 | ) | $ | (116 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (116 | ) | $ | (116 | ) | ||||||
Net assets (liabilities)(3) | $ | 160 | $ | 142 | $ | (4 | ) | $ | 298 | |||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 20 | $ | — | $ | 20 | ||||||||
| Derivative assets — commodity contracts | — | 9 | — | 9 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 176 | 176 | ||||||||||||
Equity securities(2) | 133 | — | — | 133 | ||||||||||||
| U.S. government debt securities | — | 30 | — | 30 | ||||||||||||
| U.S. state debt securities | — | 82 | — | 82 | ||||||||||||
| Other | — | 2 | — | 2 | ||||||||||||
Total assets | $ | 133 | $ | 143 | $ | 176 | $ | 452 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (143 | ) | $ | (143 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (143 | ) | $ | (143 | ) | ||||||
Net assets (liabilities)(3) | $ | 133 | $ | 143 | $ | 33 | $ | 309 | ||||||||
| (1) | NUG contracts are subject to regulatory accounting and do not impact earnings. | |
| (2) | NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index. | |
| (3) | Excludes $(9) million and $1 million as of December 31, 2010 and 2009, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
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Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2010 and 2009:
| Derivative Asset | Derivative Liability | Net | ||||||||||
| NUG Contracts(1) | NUG Contracts(1) | NUG Contracts(1) | ||||||||||
| (In millions) | ||||||||||||
| January 1, 2010 Balance | $ | 176 | $ | (143 | ) | $ | 33 | |||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (59 | ) | (38 | ) | (97 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | (5 | ) | 65 | 60 | ||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2010 Balance | $ | 112 | $ | (116 | ) | $ | (4 | ) | ||||
| January 1, 2009 Balance | $ | 300 | $ | (150 | ) | $ | 150 | |||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (124 | ) | (81 | ) | (205 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | — | 88 | 88 | |||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2009 Balance | $ | 176 | $ | (143 | ) | $ | 33 | |||||
| (1) | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
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Pennsylvania Electric Company
The following tables provide the fair value measurement amounts for assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of December 31, 2010 and 2009:
| December 31, 2010 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 8 | $ | — | $ | 8 | ||||||||
| Derivative assets — commodity contracts | — | 2 | — | 2 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 4 | 4 | ||||||||||||
Equity securities(2) | 81 | — | — | 81 | ||||||||||||
| U.S. government debt securities | — | 9 | — | 9 | ||||||||||||
| U.S. state debt securities | — | 133 | — | 133 | ||||||||||||
| Other | — | 5 | — | 5 | ||||||||||||
Total assets | $ | 81 | $ | 157 | $ | 4 | $ | 242 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (117 | ) | $ | (117 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (117 | ) | $ | (117 | ) | ||||||
Net assets (liabilities)(3) | $ | 81 | $ | 157 | $ | (113 | ) | $ | 125 | |||||||
| December 31, 2009 | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| (In millions) | ||||||||||||||||
Assets | ||||||||||||||||
| Corporate debt securities | $ | — | $ | 6 | $ | — | $ | 6 | ||||||||
| Derivative assets — commodity contracts | — | 5 | — | 5 | ||||||||||||
Derivative assets — NUG contracts(1) | — | — | 16 | 16 | ||||||||||||
Equity securities(2) | 74 | — | — | 74 | ||||||||||||
| U.S. government debt securities | — | 9 | — | 9 | ||||||||||||
| U.S. state debt securities | — | 151 | — | 151 | ||||||||||||
| Other | — | 20 | — | 20 | ||||||||||||
Total assets | $ | 74 | $ | 191 | $ | 16 | $ | 281 | ||||||||
Liabilities | ||||||||||||||||
Derivative liabilities — NUG contracts(1) | $ | — | $ | — | $ | (101 | ) | $ | (101 | ) | ||||||
Total liabilities | $ | — | $ | — | $ | (101 | ) | $ | (101 | ) | ||||||
Net assets (liabilities)(3) | $ | 74 | $ | 191 | $ | (85 | ) | $ | 180 | |||||||
| (1) | NUG contracts are subject to regulatory accounting and do not impact earnings. | |
| (2) | NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Index or Russell 3000 Index. | |
| (3) | Excludes $(3) million and $3 million as of December 31, 2010 and 2009, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
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Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy for the years ending December 31, 2010 and 2009:
| Derivative Asset | Derivative Liability | Net | ||||||||||
| NUG Contracts(1) | NUG Contracts(1) | NUG Contracts(1) | ||||||||||
| (In millions) | ||||||||||||
| January 1, 2010 Balance | $ | 16 | $ | (101 | ) | $ | (85 | ) | ||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (11 | ) | (108 | ) | (119 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | (1 | ) | 92 | 91 | ||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2010 Balance | $ | 4 | $ | (117 | ) | $ | (113 | ) | ||||
| January 1, 2009 Balance | $ | 120 | $ | (84 | ) | $ | 36 | |||||
| Realized gain (loss) | — | — | — | |||||||||
| Unrealized gain (loss) | (104 | ) | (119 | ) | (223 | ) | ||||||
| Purchases | — | — | — | |||||||||
| Issuances | — | — | — | |||||||||
| Sales | — | — | — | |||||||||
| Settlements | — | 102 | 102 | |||||||||
| Transfers in (out) of Level 3 | — | — | — | |||||||||
| December 31, 2009 Balance | $ | 16 | $ | (101 | ) | $ | (85 | ) | ||||
| (1) | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
6. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost under the accrual method of accounting. The changes in the fair value of derivative instruments that do not meet the normal purchases and normal sales criteria are included in purchased power, other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item. Based on derivative contracts held as of December 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $16 million ($10 million net of tax) during the next twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease annual net income by approximately $1 million.
Cash Flow Hedges
FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of December 31, 2010, no forward starting swap agreements were outstanding.
Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $92 million ($60 million net of tax) as of December 31, 2010. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. The table below provides the activity of AOCL related to interest rate cash flow hedges for the years ended December 31, 2010 and 2009.
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| Years Ended December 31, | ||||||||
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| Effective Portion | ||||||||
| Loss Recognized in AOCL | $ | — | $ | (18 | ) | |||
| Reclassification from AOCL into Interest Expense | (11 | ) | (40 | ) | ||||
Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivatives were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of December 31, 2010, no fixed-for-floating interest rate swap agreements were outstanding.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $124 million ($80 million net of tax) as of December 31, 2010. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled $12 million during 2010.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances where the hedging relationship does not qualify for hedge accounting.
The following tables summarize the fair value of commodity derivatives on FirstEnergy’s Consolidated Balance Sheets:
| Cash Flow Hedges | ||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | |||||||||||||||||||
| Fair Value | Fair Value | |||||||||||||||||||
| December 31, | December 31, | December 31, | December 31, | |||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||
| Electricity Forwards | Electricity Forwards | |||||||||||||||||||
| Current Assets | $ | 55 | $ | 3 | Current Liabilities | $ | 58 | $ | 7 | |||||||||||
| Noncurrent Assets | 49 | 11 | Noncurrent Liabilities | 43 | 12 | |||||||||||||||
| Natural Gas Futures | Natural Gas Futures | |||||||||||||||||||
| Current Assets | — | — | Current Liabilities | — | 9 | |||||||||||||||
| Noncurrent Assets | — | — | Noncurrent Liabilities | — | — | |||||||||||||||
| Other | Other | |||||||||||||||||||
| Current Assets | — | — | Current Liabilities | — | 2 | |||||||||||||||
| Noncurrent Assets | — | — | Noncurrent Liabilities | — | — | |||||||||||||||
| $ | 104 | $ | 14 | $ | 101 | $ | 30 | |||||||||||||
| Economic Hedges | ||||||||||||||||||||
| Derivative Assets | Derivative Liabilities | |||||||||||||||||||
| Fair Value | Fair Value | |||||||||||||||||||
| December 31, | December 31, | December 31, | December 31, | |||||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||
| NUG Contracts | NUG Contracts | |||||||||||||||||||
| Power Purchase | Power Purchase | |||||||||||||||||||
| Contract Asset | $ | 122 | $ | 200 | Contract Liability | $ | 466 | $ | 643 | |||||||||||
| Other | Other | |||||||||||||||||||
| Current Assets | 96 | — | Current Liabilities | 208 | 106 | |||||||||||||||
| Noncurrent Assets | 50 | 19 | Noncurrent Liabilities | 38 | 97 | |||||||||||||||
| 268 | 219 | 712 | 846 | |||||||||||||||||
| Total Commodity Derivatives | $ | 372 | $ | 233 | Total Commodity Derivatives | $ | 813 | $ | 876 | |||||||||||
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Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of December 31, 2010:
| Purchases | Sales | Net | Units | |||||||||||||
| (In thousands) | ||||||||||||||||
| Electricity Forwards | 42,227 | (45,164 | ) | (2,937 | ) | MWH | ||||||||||
The effect of derivative instruments on the Consolidated Statements of Income and Comprehensive Income for the years ended December 31, 2010 and 2009 are summarized in the following tables:
| Electricity | Natural Gas | Heating Oil | ||||||||||||||
| Derivatives in Cash Flow Hedging Relationships | Forwards | Futures | Futures | Total | ||||||||||||
| (In millions) | ||||||||||||||||
2010 | ||||||||||||||||
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | — | $ | (1 | ) | $ | — | $ | (1 | ) | ||||||
Effective Gain (Loss) Reclassified to: (1) | ||||||||||||||||
| Purchased Power Expense | (12 | ) | — | — | (12 | ) | ||||||||||
| Fuel Expense | — | (10 | ) | (3 | ) | (13 | ) | |||||||||
2009 | ||||||||||||||||
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | 7 | $ | (9 | ) | $ | 1 | $ | (1 | ) | ||||||
Effective Gain (Loss) Reclassified to: (1) | ||||||||||||||||
| Purchased Power Expense | (6 | ) | — | — | (6 | ) | ||||||||||
| Fuel Expense | — | (9 | ) | (12 | ) | (21 | ) | |||||||||
| (1) | The ineffective portion was immaterial. |
| NUG | ||||||||||||
| Derivatives Not in Hedging Relationships | Contracts | Other | Total | |||||||||
| (In millions) | ||||||||||||
2010 | ||||||||||||
| Unrealized Gain (Loss) Recognized in: | ||||||||||||
| Purchased Power Expense | $ | — | $ | (24 | ) | $ | (24 | ) | ||||
Regulatory Assets (1) | (181 | ) | — | (181 | ) | |||||||
| $ | (181 | ) | $ | (24 | ) | $ | (205 | ) | ||||
| Realized Gain (Loss) Reclassified to: | ||||||||||||
| Purchased Power Expense | $ | — | $ | (118 | ) | $ | (118 | ) | ||||
Regulatory Assets (1) | (279 | ) | 9 | (270 | ) | |||||||
| $ | (279 | ) | $ | (109 | ) | $ | (388 | ) | ||||
2009 | ||||||||||||
| Unrealized Gain (Loss) Recognized in: | ||||||||||||
| Purchased Power Expense | $ | — | $ | (203 | ) | $ | (203 | ) | ||||
| Fuel Expense | — | (1 | ) | (1 | ) | |||||||
Regulatory Assets (1) | (470 | ) | — | (470 | ) | |||||||
| $ | (470 | ) | $ | (204 | ) | $ | (674 | ) | ||||
| Realized Gain (Loss) Reclassified to: | ||||||||||||
| Purchased Power Expense | $ | — | $ | 1 | $ | 1 | ||||||
| Fuel Expense | — | (1 | ) | (1 | ) | |||||||
Regulatory Assets (1) | (358 | ) | 10 | (348 | ) | |||||||
| $ | (358 | ) | $ | 10 | $ | (348 | ) | |||||
| (1) | The realized gain (loss) is reclassified upon termination of the derivative instrument. |
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Total unamortized gains included in AOCL associated with commodity derivatives were $8 million ($5 million net of tax) as of December 31, 2010, as compared to unamortized losses of $15 million ($9 million net of tax) as of December 31, 2009. The net of tax change resulted from a net $1 million loss related to current hedging activity offset by $15 million of net hedge losses reclassified to earnings during 2010. Based on current estimates, approximately $3 million (net of tax) of the net deferred losses on derivative instruments in AOCL as of December 31, 2010 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuates from period to period based on various market factors.
As of December 31, 2010, FES’ net liability position under commodity derivative contracts was $107 million. Under these commodity derivative contracts, FES posted collateral of $156 million. Certain commodity derivative contracts include credit risk-related contingent features that would require FES to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that were in a liability position on December 31, 2010 was $102 million, for which $91 million in collateral has been posted. If FES’ credit rating were to fall below investment grade, it would be required to post $24 million of additional collateral related to commodity derivatives.
7. LEASES
FirstEnergy leases certain generating facilities, office space and other property and equipment under cancelable and noncancelable leases.
In 1987, OE sold portions of its ownership interests in Perry Unit 1 and Beaver Valley Unit 2 and entered into operating leases on the portions sold for basic lease terms of approximately 29 years. In that same year, CEI and TE also sold portions of their ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3 and entered into similar operating leases for lease terms of approximately 30 years. During the terms of their respective leases, OE, CEI and TE are responsible, to the extent of their leasehold interests, for costs associated with the units including construction expenditures, operation and maintenance expenses, insurance, nuclear fuel, property taxes and decommissioning. They have the right, at the expiration of the respective basic lease terms, to renew their respective leases. They also have the right to purchase the facilities at the expiration of the basic lease term or any renewal term at a price equal to the fair market value of the facilities. The basic rental payments are adjusted when applicable federal tax law changes.
Effective October 16, 2007 CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO and FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 13, 2007 Bruce Mansfield Unit 1 sale and leaseback transaction, to a newly formed wholly-owned subsidiary on December 17, 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
In 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1 and entered into operating leases for basic lease terms of approximately 33 years. FES has unconditionally and irrevocably guaranteed all of FGCO’s obligations under each of the leases.
During 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.
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Rentals for capital and operating leases for the three years ended December 31, 2010 are summarized as follows:
| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
| Operating leases | $ | 228 | $ | 202 | $ | 147 | $ | 4 | $ | 64 | $ | 9 | $ | 7 | $ | 4 | ||||||||||||||||
| Capital leases | ||||||||||||||||||||||||||||||||
| Interest element | 2 | 1 | — | 1 | — | — | — | — | ||||||||||||||||||||||||
Other(1) | 11 | 10 | — | — | — | — | 1 | — | ||||||||||||||||||||||||
| Total rentals | $ | 241 | $ | 213 | $ | 147 | $ | 5 | $ | 64 | $ | 9 | $ | 8 | $ | 4 | ||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||
| Operating leases | $ | 236 | $ | 202 | $ | 146 | $ | 4 | $ | 64 | $ | 9 | $ | 7 | $ | 4 | ||||||||||||||||
| Capital leases | ||||||||||||||||||||||||||||||||
| Interest element | 1 | 2 | 1 | 1 | — | — | — | — | ||||||||||||||||||||||||
Other(1) | 6 | 10 | — | — | — | — | — | — | ||||||||||||||||||||||||
| Total rentals | $ | 243 | $ | 214 | $ | 147 | $ | 5 | $ | 64 | $ | 9 | $ | 7 | $ | 4 | ||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||
| Operating leases | $ | 381 | $ | 173 | $ | 146 | $ | 5 | $ | 65 | $ | 8 | $ | 4 | $ | 4 | ||||||||||||||||
| Capital leases | ||||||||||||||||||||||||||||||||
| Interest element | 1 | 1 | — | — | — | — | — | — | ||||||||||||||||||||||||
Other(1) | 6 | 8 | — | 1 | — | — | — | — | ||||||||||||||||||||||||
| Total rentals | $ | 388 | $ | 182 | $ | 146 | $ | 6 | $ | 65 | $ | 8 | $ | 4 | $ | 4 | ||||||||||||||||
| (1) | Includes $6 million in 2010 and 2009, respectively, and $5 million in 2008, at FE and FES for wind purchased power agreements classified as capital leases. |
The future minimum capital lease payments as of December 31, 2010 are as follows (OE, TE, JCP&L, Met-Ed and Penelec have no material capital leases):
| Capital leases | FE | FES | CEI | |||||||||
| (In millions) | ||||||||||||
| 2011 | $ | 7 | $ | 6 | $ | 1 | ||||||
| 2012 | 7 | 6 | 1 | |||||||||
| 2013 | 7 | 6 | 1 | |||||||||
| 2014 | 7 | 6 | 1 | |||||||||
| 2015 | 7 | 5 | 1 | |||||||||
| Years thereafter | 14 | 12 | 2 | |||||||||
| Total minimum lease payments | 49 | 41 | 7 | |||||||||
| Executory costs | — | — | — | |||||||||
| Net minimum lease payments | 49 | 41 | 7 | |||||||||
| Interest portion | (10 | ) | (5 | ) | (4 | ) | ||||||
| Present value of net minimum lease payments | 39 | 36 | 3 | |||||||||
| Less current portion | 5 | 5 | — | |||||||||
| Noncurrent portion | $ | 34 | $ | 31 | $ | 3 | ||||||
The present value of minimum lease payments for FirstEnergy does not include $15 million of capital lease obligations that were prepaid as of December 31, 2010.
Established by OE in 1996, PNBV purchased a portion of the lease obligation bonds issued on behalf of lessors in OE’s Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions. Similarly, CEI and TE established Shippingport in 1997 to purchase the lease obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2 and 3 sale and leaseback transactions. The PNBV and Shippingport arrangements effectively reduce lease costs related to those transactions (see Note 8).
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The future minimum consolidated operating lease payments as of December 31, 2010 are as follows:
| Lease | Capital | |||||||||||
| Operating Leases | Payments | Trust | Net | |||||||||
| (In millions) | ||||||||||||
| 2011 | $ | 329 | $ | 116 | $ | 213 | ||||||
| 2012 | 365 | 125 | 240 | |||||||||
| 2013 | 367 | 130 | 237 | |||||||||
| 2014 | 363 | 131 | 232 | |||||||||
| 2015 | 365 | 91 | 274 | |||||||||
| Years thereafter | 2,150 | 32 | 2,118 | |||||||||
| Total minimum lease payments | $ | 3,939 | $ | 625 | $ | 3,314 | ||||||
| Operating Leases | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| 2011 | $ | 192 | $ | 146 | $ | 4 | $ | 64 | $ | 6 | $ | 4 | $ | 3 | ||||||||||||||
| 2012 | 230 | 147 | 3 | 64 | 5 | 4 | 3 | |||||||||||||||||||||
| 2013 | 236 | 147 | 3 | 64 | 5 | 4 | 3 | |||||||||||||||||||||
| 2014 | 234 | 146 | 3 | 64 | 5 | 4 | 2 | |||||||||||||||||||||
| 2015 | 238 | 146 | 3 | 64 | 4 | 4 | 2 | |||||||||||||||||||||
| Years thereafter | 1,895 | 166 | 6 | 79 | 48 | 40 | 23 | |||||||||||||||||||||
| Total minimum lease payments | $ | 3,025 | $ | 898 | $ | 22 | $ | 399 | $ | 73 | $ | 60 | $ | 36 | ||||||||||||||
FirstEnergy recorded above-market lease liabilities for Beaver Valley Unit 2 and the Bruce Mansfield Plant associated with the 1997 merger between OE and Centerior. The unamortized above-market lease liability for Beaver Valley Unit 2 of $236 million as of December 31, 2010, of which $37 million is classified as current, is being amortized by TE on a straight-line basis through the end of the lease term in 2017. The unamortized above-market lease liability for the Bruce Mansfield Plant of $262 million as of December 31, 2010, of which $46 million is classified as current, is being amortized by FGCO on a straight-line basis through the end of the lease term in 2016.
8. VARIABLE INTEREST ENTITIES
On January 1, 2010, FirstEnergy adopted the amendments to the consolidation topic addressing VIEs. This standard requires that FirstEnergy and its subsidiaries perform a qualitative analysis to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impacts the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. This standard also requires an ongoing reassessment of the primary beneficiary of a VIE and eliminates the quantitative approach previously required for determining whether an entity is the primary beneficiary. In order to evaluate contracts under the consolidation guidance, FirstEnergy aggregated contracts into categories based on similar risk characteristics and significance. The adoption of this new standard did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries.
FirstEnergy’s consolidated financial statements include the accounts of entities in which it has a controlling financial interest. FirstEnergy consolidates certain VIEs in which it has financial control through disproportionate economics in its equity and debt investments in the entities. These VIEs include: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $310 million was outstanding as of December 31, 2010.
FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest on the Consolidated Balance Sheets is the result of net losses of the noncontrolling interests ($24 million) and distributions to owners ($5 million) during the year ended December 31, 2010.
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Mining Operations
On July 16, 2008, FEV entered into a joint venture with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of WMB Loan Ventures LLC and WMB Loan Ventures II LLC owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. FEV consolidates the mining and transportation operations of this joint venture in its financial statements. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of WMB Loan Ventures LLC and WMB Loan Ventures II LLC to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective August 21, 2009, the joint venture acquired the remaining 20% stake in the mining operations by issuing a five-year note for $47.5 million. For both acquisitions, the difference between the consideration paid and the adjustment to the noncontrolling interest resulted in a charge to other paid in capital of approximately $30 million.
Trusts
FirstEnergy���s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
Power Purchase Agreements
FirstEnergy subsidiaries JCPL, Met-Ed and Penelec have 21 long term power purchase agreements totaling 1,339 MW with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities. FirstEnergy evaluated these power purchase agreements to determine if certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant’s variable costs of production.
FirstEnergy has determined that for all but two of these NUG entities, neither JCP&L, nor Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations that are not within the scope of consolidation consideration for VIEs. JCP&L may hold variable interests in the remaining two entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. However, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Since JCP&L has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it incurs for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs related to the two contracts that may contain a variable interest were $243 million and $225 million for the years ended December 31, 2010 and 2009, respectively.
Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.
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FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of December 31, 2010:
| Maximum | Discounted Lease | Net | ||||||||||
| Exposure | Payments, net(1) | Exposure | ||||||||||
| (In millions) | ||||||||||||
| FES | $ | 1,360 | $ | 1,167 | $ | 193 | ||||||
| OE | 666 | 474 | 192 | |||||||||
CEI(2) | 622 | 72 | 550 | |||||||||
TE(2) | 622 | 346 | 276 | |||||||||
| (1) | The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion. | |
| (2) | CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements. |
See Note 7 for a discussion of CEI’s and TE’s assignment of their leasehold interests in the Bruce Mansfield Plant to FGCO.
9. INCOME TAXES
Income Taxes
FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. Details of income taxes for the three years ended December 31, 2010 are shown below:
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| PROVISION FOR INCOME TAXES | FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
| Currently payable- | ||||||||||||||||||||||||||||||||
| Federal | $ | (23 | ) | $ | (23 | ) | $ | 37 | $ | 58 | $ | (9 | ) | $ | 81 | $ | 1 | $ | (81 | ) | ||||||||||||
| State | 35 | (2 | ) | (2 | ) | 1 | (1 | ) | 36 | 12 | (12 | ) | ||||||||||||||||||||
| 12 | (25 | ) | 35 | 59 | (10 | ) | 117 | 13 | (93 | ) | ||||||||||||||||||||||
| Deferred, net- | ||||||||||||||||||||||||||||||||
| Federal | 451 | 165 | 45 | (15 | ) | 27 | 30 | 33 | 117 | |||||||||||||||||||||||
| State | 28 | 15 | 3 | (4 | ) | 1 | 1 | (3 | ) | 17 | ||||||||||||||||||||||
| 479 | 180 | 48 | (19 | ) | 28 | 31 | 30 | 134 | ||||||||||||||||||||||||
| Investment tax credit amortization | (9 | ) | (4 | ) | (1 | ) | (1 | ) | — | — | — | — | ||||||||||||||||||||
| Total provision for income taxes | $ | 482 | $ | 151 | $ | 82 | $ | 39 | $ | 18 | $ | 148 | $ | 43 | - | 41 | ||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||
| Currently payable- | ||||||||||||||||||||||||||||||||
| Federal | $ | (183 | ) | $ | 87 | $ | 21 | $ | 40 | $ | 6 | $ | 40 | $ | (34 | ) | $ | (21 | ) | |||||||||||||
| State | 44 | 8 | 4 | 2 | — | 26 | (4 | ) | 4 | |||||||||||||||||||||||
| (139 | ) | 95 | 25 | 42 | 6 | 66 | (38 | ) | (17 | ) | ||||||||||||||||||||||
| Deferred, net- | ||||||||||||||||||||||||||||||||
| Federal | 351 | 200 | 40 | (52 | ) | — | 41 | 60 | 60 | |||||||||||||||||||||||
| State | 42 | 24 | 3 | 1 | 2 | 2 | 7 | 4 | ||||||||||||||||||||||||
| 393 | 224 | 43 | (51 | ) | 2 | 43 | 67 | 64 | ||||||||||||||||||||||||
| Investment tax credit amortization | (9 | ) | (4 | ) | (2 | ) | (1 | ) | — | — | — | (1 | ) | |||||||||||||||||||
| Total provision for income taxes | $ | 245 | $ | 315 | $ | 66 | $ | (10 | ) | $ | 8 | $ | 109 | $ | 29 | $ | 46 | |||||||||||||||
2008 | ||||||||||||||||||||||||||||||||
| Currently payable- | ||||||||||||||||||||||||||||||||
| Federal | $ | 355 | $ | 156 | $ | 79 | $ | 119 | $ | 46 | $ | 101 | $ | 5 | $ | (34 | ) | |||||||||||||||
| State | 56 | 20 | 4 | 6 | — | 34 | 6 | (3 | ) | |||||||||||||||||||||||
| 411 | 176 | 83 | 125 | 46 | 135 | 11 | (37 | ) | ||||||||||||||||||||||||
| Deferred, net- | ||||||||||||||||||||||||||||||||
| Federal | 343 | 109 | 22 | 16 | (12 | ) | 9 | 47 | 84 | |||||||||||||||||||||||
| State | 36 | 12 | (2 | ) | (2 | ) | (4 | ) | 4 | 4 | 12 | |||||||||||||||||||||
| 379 | 121 | 20 | 14 | (16 | ) | 13 | 51 | 96 | ||||||||||||||||||||||||
| Investment tax credit amortization | (13 | ) | (4 | ) | (4 | ) | (2 | ) | — | — | (1 | ) | (1 | ) | ||||||||||||||||||
| Total provision for income taxes | $ | 777 | $ | 293 | $ | 99 | $ | 137 | $ | 30 | $ | 148 | $ | 61 | $ | 58 | ||||||||||||||||
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflects the anticipated increase in income taxes that will occur as a result of the change in tax law.
FES and the Utilities are party to an intercompany income tax allocation agreement with FirstEnergy and its other subsidiaries that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FirstEnergy, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit.
The following tables provide a reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes for the three years ended December 31, 2010.
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| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
| Book income before provision for income taxes | $ | 1,266 | $ | 420 | $ | 239 | $ | 110 | $ | 51 | $ | 340 | $ | 101 | $ | 101 | ||||||||||||||||
| Federal income tax expense at statutory rate | $ | 443 | $ | 147 | $ | 84 | $ | 39 | $ | 18 | $ | 119 | $ | 35 | $ | 35 | ||||||||||||||||
| Increases (reductions) in taxes resulting from- | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (9 | ) | (4 | ) | (1 | ) | (1 | ) | — | — | — | — | ||||||||||||||||||||
| State income taxes, net of federal tax benefit | 41 | 9 | 1 | (2 | ) | — | 24 | 6 | 3 | |||||||||||||||||||||||
| Manufacturing deduction | — | 2 | (2 | ) | — | — | — | — | — | |||||||||||||||||||||||
| Medicare Part D | 13 | — | — | 3 | 1 | 3 | 2 | 3 | ||||||||||||||||||||||||
| Effectively settled tax items | (34 | ) | (2 | ) | (9 | ) | (4 | ) | (3 | ) | — | — | — | |||||||||||||||||||
| Other, net | 28 | (1 | ) | 9 | 4 | 2 | 2 | — | — | |||||||||||||||||||||||
| Total provision for income taxes | $ | 482 | $ | 151 | $ | 82 | $ | 39 | $ | 18 | $ | 148 | $ | 43 | $ | 41 | ||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||
| Book income before provision for income taxes | $ | 1,251 | $ | 892 | $ | 188 | $ | (23 | ) | $ | 32 | $ | 279 | $ | 84 | $ | 111 | |||||||||||||||
| Federal income tax expense at statutory rate | $ | 438 | $ | 312 | $ | 66 | $ | (8 | ) | $ | 11 | $ | 98 | $ | 29 | $ | 39 | |||||||||||||||
| Increases (reductions) in taxes resulting from- | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (9 | ) | (4 | ) | (2 | ) | (1 | ) | — | — | — | (1 | ) | |||||||||||||||||||
| State income taxes, net of federal tax benefit | 56 | 21 | 5 | 2 | 1 | 18 | 2 | 5 | ||||||||||||||||||||||||
| Manufacturing deduction | (13 | ) | (11 | ) | (2 | ) | 1 | (1 | ) | — | — | — | ||||||||||||||||||||
| Effectively settled tax items | (217 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Other, net | (10 | ) | (3 | ) | (1 | ) | (4 | ) | (3 | ) | (7 | ) | (2 | ) | 3 | |||||||||||||||||
| Total provision for income taxes | $ | 245 | $ | 315 | $ | 66 | $ | (10 | ) | $ | 8 | $ | 109 | $ | 29 | $ | 46 | |||||||||||||||
2008 | ||||||||||||||||||||||||||||||||
| Book income before provision for income taxes | $ | 2,119 | $ | 800 | $ | 310 | $ | 421 | $ | 105 | $ | 335 | $ | 149 | $ | 146 | ||||||||||||||||
| Federal income tax expense at statutory rate | $ | 742 | $ | 280 | $ | 109 | $ | 147 | $ | 37 | $ | 117 | $ | 52 | $ | 51 | ||||||||||||||||
| Increases (reductions) in taxes resulting from- | ||||||||||||||||||||||||||||||||
| Amortization of investment tax credits | (13 | ) | (4 | ) | (4 | ) | (2 | ) | — | — | (1 | ) | (1 | ) | ||||||||||||||||||
| State income taxes, net of federal tax benefit | 60 | 21 | 1 | 2 | (2 | ) | 25 | 7 | 5 | |||||||||||||||||||||||
| Manufacturing deduction | (29 | ) | (16 | ) | (3 | ) | (8 | ) | (2 | ) | — | — | — | |||||||||||||||||||
| Effectively settled tax items | (14 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Other, net | 31 | 12 | (4 | ) | (2 | ) | (3 | ) | 6 | 3 | 3 | |||||||||||||||||||||
| Total provision for income taxes | $ | 777 | $ | 293 | $ | 99 | $ | 137 | $ | 30 | $ | 148 | $ | 61 | $ | 58 | ||||||||||||||||
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Accumulated deferred income taxes as of December 31, 2010 and 2009 are as follows:
| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
DECEMBER 31, 2010 | ||||||||||||||||||||||||||||||||
| Property basis differences | $ | 3,617 | $ | 645 | $ | 571 | $ | 471 | $ | 196 | $ | 651 | $ | 354 | $ | 439 | ||||||||||||||||
| Regulatory transition charge | 235 | 12 | 37 | 89 | 3 | 95 | (1 | ) | — | |||||||||||||||||||||||
| Customer receivables for future income taxes | 113 | — | — | — | — | 13 | 48 | 52 | ||||||||||||||||||||||||
| Deferred customer shopping incentive | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Deferred MISO/PJM transmission costs | 85 | — | — | — | — | — | 62 | 23 | ||||||||||||||||||||||||
| Other regulatory assets — RCP | 166 | — | 82 | 56 | 28 | — | — | — | ||||||||||||||||||||||||
| Deferred sale and leaseback gain | (469 | ) | (412 | ) | (35 | ) | — | — | (10 | ) | (12 | ) | — | |||||||||||||||||||
| Nonutility generation costs | 51 | — | — | — | — | — | 55 | (4 | ) | |||||||||||||||||||||||
| Unamortized investment tax credits | (44 | ) | (20 | ) | (4 | ) | (4 | ) | (2 | ) | (2 | ) | (5 | ) | (4 | ) | ||||||||||||||||
| Unrealized losses on derivative hedges | (29 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Pension and other postretirement obligations | (686 | ) | (99 | ) | (57 | ) | (31 | ) | (27 | ) | (74 | ) | (13 | ) | (81 | ) | ||||||||||||||||
| Lease market valuation liability | (197 | ) | (82 | ) | — | — | (81 | ) | — | — | — | |||||||||||||||||||||
| Oyster Creek securitization (Note 11(C)) | 109 | — | — | — | — | 109 | — | — | ||||||||||||||||||||||||
| Nuclear decommissioning activities | 47 | 79 | 7 | (1 | ) | 15 | (8 | ) | 2 | (47 | ) | |||||||||||||||||||||
| Mark-to-market adjustments | (42 | ) | (42 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| Deferred gain for asset sales — affiliated companies | — | — | 34 | 22 | 7 | — | — | — | ||||||||||||||||||||||||
| Allowance for equity funds used used during construction | 12 | — | 12 | — | — | — | — | — | ||||||||||||||||||||||||
| Loss carryforwards | (41 | ) | (10 | ) | — | — | — | — | — | (23 | ) | |||||||||||||||||||||
| Loss carryforward valuation reserve | 21 | 9 | — | — | — | — | — | 7 | ||||||||||||||||||||||||
| All other | (69 | ) | (22 | ) | 49 | 21 | (7 | ) | (58 | ) | (17 | ) | 10 | |||||||||||||||||||
| Net deferred income tax liability | $ | 2,879 | $ | 58 | $ | 696 | $ | 623 | $ | 132 | $ | 716 | $ | 473 | $ | 372 | ||||||||||||||||
DECEMBER 31, 2009 | ||||||||||||||||||||||||||||||||
| Property basis differences | $ | 3,049 | $ | 619 | $ | 508 | $ | 419 | $ | 177 | $ | 458 | $ | 275 | $ | 350 | ||||||||||||||||
| Regulatory transition charge | 334 | — | 67 | 95 | 2 | 157 | 13 | — | ||||||||||||||||||||||||
| Customer receivables for future income taxes | 111 | — | — | — | — | 13 | 49 | 49 | ||||||||||||||||||||||||
| Deferred customer shopping incentive | 55 | — | — | 55 | — | — | — | — | ||||||||||||||||||||||||
| Deferred MISO/PJM transmission costs | 89 | — | — | — | — | — | 90 | (1 | ) | |||||||||||||||||||||||
| Other regulatory assets — RCP | 162 | — | 80 | 54 | 28 | — | ||||||||||||||||||||||||||
| Deferred sale and leaseback gain | (486 | ) | (426 | ) | (40 | ) | — | — | (9 | ) | (11 | ) | — | |||||||||||||||||||
| Nonutility generation costs | 9 | — | — | — | — | — | 48 | (39 | ) | |||||||||||||||||||||||
| Unamortized investment tax credits | (48 | ) | (22 | ) | (4 | ) | (4 | ) | (2 | ) | (2 | ) | (5 | ) | (4 | ) | ||||||||||||||||
| Unrealized losses on derivative hedges | (44 | ) | (8 | ) | — | — | — | (1 | ) | (1 | ) | — | ||||||||||||||||||||
| Pension and other postretirement obligations | (611 | ) | (75 | ) | (57 | ) | (18 | ) | (34 | ) | (72 | ) | (20 | ) | (83 | ) | ||||||||||||||||
| Lease market valuation liability | (232 | ) | (101 | ) | — | — | (111 | ) | — | — | — | |||||||||||||||||||||
| Oyster Creek securitization (Note 11(C)) | 132 | — | — | — | — | 132 | — | — | ||||||||||||||||||||||||
| Nuclear decommissioning activities | (34 | ) | 23 | 5 | — | 12 | (19 | ) | (1 | ) | (52 | ) | ||||||||||||||||||||
| Mark-to-market adjustments | (76 | ) | (76 | ) | — | — | — | — | — | — | ||||||||||||||||||||||
| Deferred gain for asset sales — affiliated companies | — | — | 37 | 25 | 8 | — | — | — | ||||||||||||||||||||||||
| Allowance for equity funds used used during construction | 15 | — | 15 | — | — | — | — | — | ||||||||||||||||||||||||
| Loss carryforwards | (33 | ) | (8 | ) | — | — | — | — | — | (13 | ) | |||||||||||||||||||||
| Loss carryforward valuation reserve | 21 | 7 | — | — | — | — | — | 5 | ||||||||||||||||||||||||
| All other | 55 | (20 | ) | 49 | 19 | 1 | 31 | 16 | 30 | |||||||||||||||||||||||
| Net deferred income tax liability (asset) | $ | 2,468 | $ | (87 | ) | $ | 660 | $ | 645 | $ | 81 | $ | 688 | $ | 453 | $ | 242 | |||||||||||||||
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FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company’s tax return. After reaching settlements at appeals in 2010 related primarily to the capitalization of certain costs for the tax years 2004-2008 and an unrelated federal tax matter related to prior year gains and losses recognized from the disposition of assets, as well as receiving final approval from the Joint Committee on Taxation for several items that were under appeals for tax years 2001-2003, FirstEnergy recognized approximately $78 million of net tax benefits in 2010, including $21 million that favorably affected FirstEnergy’s effective tax rate. The remaining portion of the tax benefit increased FirstEnergy’s accumulated deferred income taxes.
Upon reaching a settlement on several items under appeal for the tax years 2001-2003, as well as other items that effectively settled in 2009, FirstEnergy recognized approximately $100 million of net tax benefits, including $161 million that favorably affected FirstEnergy’s effective tax rate. The offsetting $61 million primarily related to tax items where the uncertainty was removed and the tax refund will be received when the tax years are closed.
Upon completion of the federal tax examinations for tax years 2004-2006, as well as other tax settlements reached in 2008, FirstEnergy recognized approximately $42 million of net tax benefits, including $7 million that favorably affected FirstEnergy’s effective tax rate. The remaining balance of the tax benefits recognized in 2008 adjusted goodwill as a purchase price adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million).
As of December 31, 2010, it is reasonably possible that approximately $42 million of the unrecognized benefits may be resolved within the next twelve months, of which up to approximately $2 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.
In 2009, FirstEnergy, on behalf of the Utilities, filed a change in accounting method related to the costs to repair and maintain electric utility network (transmission and distribution) assets. In 2010, approximately $325 million of costs were included as a repair deduction on FirstEnergy’s 2009 consolidated tax return, which reduced taxable income and increased the amount of tax refunds that were applied to FirstEnergy’s 2010 estimated federal tax payments. Due to the flow through of the Pennsylvania state income tax benefit for this change in accounting, FirstEnergy’s effective tax rate was reduced by $6 million in 2010. In connection with completing FirstEnergy’s 2009 consolidated tax return, FES recognized an $8 million adjustment that increased its income tax expense in 2010. The effects of these adjustments were not material to 2009 or 2010.
In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and $281 million of costs were included as a repair deduction on FirstEnergy’s 2008 consolidated tax return. Since the IRS did not complete its review over this change in accounting method by the extended filing date of FirstEnergy’s federal tax return, FirstEnergy increased the amount of unrecognized tax benefits by $34 million in the third quarter of 2009, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There was no impact on FirstEnergy’s effective tax rate for 2009.
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| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Balance, January 1, 2010 | $ | 191 | $ | 41 | $ | 77 | $ | 29 | $ | 6 | $ | 14 | $ | 13 | $ | 11 | ||||||||||||||||
| Increase for tax positions related to the current year | 10 | 6 | 2 | (1 | ) | — | — | 2 | 1 | |||||||||||||||||||||||
| Increase for tax positions related to prior years | 2 | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Decrease for tax positions related to prior years | (81 | ) | (4 | ) | (19 | ) | (15 | ) | (6 | ) | (21 | ) | (2 | ) | (5 | ) | ||||||||||||||||
| Decrease for settlement | (77 | ) | (2 | ) | (58 | ) | (14 | ) | — | 7 | (11 | ) | (6 | ) | ||||||||||||||||||
| Balance, December 31, 2010 | $ | 45 | $ | 41 | $ | 2 | $ | (1 | ) | $ | — | $ | — | $ | 2 | $ | 1 | |||||||||||||||
| Balance, January 1, 2009 | $ | 219 | $ | 5 | $ | (30 | ) | $ | (26 | ) | $ | (4 | ) | $ | 42 | $ | 28 | $ | 24 | |||||||||||||
| Increase for tax positions related to the current year | 41 | 34 | 4 | 3 | — | — | — | — | ||||||||||||||||||||||||
| Increase for tax positions related to prior years | 46 | 2 | 103 | 52 | 10 | — | — | — | ||||||||||||||||||||||||
| Decrease for tax positions related to prior years | (100 | ) | — | — | — | — | (28 | ) | (15 | ) | (13 | ) | ||||||||||||||||||||
| Decrease for settlement | (15 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||
| Balance, December 31, 2009 | $ | 191 | $ | 41 | $ | 77 | $ | 29 | $ | 6 | $ | 14 | $ | 13 | $ | 11 | ||||||||||||||||
| Balance, January 1, 2008 | $ | 272 | $ | 14 | $ | (12 | ) | $ | (17 | ) | $ | (1 | ) | $ | 38 | $ | 24 | $ | 16 | |||||||||||||
| Increase for tax positions related to the current year | 14 | — | 1 | — | — | — | — | — | ||||||||||||||||||||||||
| Increase for tax positions related to prior years | — | 1 | 1 | — | — | 6 | 5 | 9 | ||||||||||||||||||||||||
| Decrease for tax positions related to prior years | (56 | ) | (10 | ) | (14 | ) | (8 | ) | (3 | ) | (2 | ) | (1 | ) | (1 | ) | ||||||||||||||||
| Decrease for settlement | (11 | ) | — | (6 | ) | (1 | ) | — | — | — | — | |||||||||||||||||||||
| Balance, December 31, 2008 | $ | 219 | $ | 5 | $ | (30 | ) | $ | (26 | ) | $ | (4 | ) | $ | 42 | $ | 28 | $ | 24 | |||||||||||||
FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The reversal of accrued interest associated with the recognized tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $12 million in 2010. The reversal of accrued interest associated with the $161 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate in 2009 by $56 million and an interest receivable of $11 million was removed from the accrued interest for uncertain tax positions. The reversal of accrued interest associated with the $56 million in recognized tax benefits favorably affected FirstEnergy’s effective tax rate in 2008 by $12 million and an interest receivable of $4 million was removed from the accrued interest for uncertain tax positions. During the years ended December 31, 2010, 2009 and 2008, FirstEnergy recognized net interest expense (income) of approximately $(10) million, $(49) million and $2 million, respectively. The net amount of interest accrued as of December 31, 2010 and 2009 was $3 million and $21 million, respectively.
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The following table summarizes the net interest expense (income) recognized by FES and the Utilities for the three years ended December 31, 2010 and the cumulative net interest payable (receivable) as of December 31, 2010 and 2009:
| Net Interest Expense (Income) | ||||||||||||||||||||
| For the Years Ended | Net Interest Payable | |||||||||||||||||||
| December 31, | As of December 31, | |||||||||||||||||||
| 2010 | 2009 | 2008 | 2010 | 2009 | ||||||||||||||||
| (In millions) | (In millions) | |||||||||||||||||||
| FES | $ | 1 | $ | (1 | ) | $ | — | $ | 2 | $ | 2 | |||||||||
| OE | (3 | ) | 4 | (4 | ) | 1 | 9 | |||||||||||||
| CEI | (2 | ) | 3 | (2 | ) | — | 3 | |||||||||||||
| TE | (1 | ) | — | — | — | 1 | ||||||||||||||
| JCP&L | (2 | ) | (4 | ) | 1 | — | 1 | |||||||||||||
| Met-Ed | — | (2 | ) | 1 | — | 1 | ||||||||||||||
| Penelec | — | (1 | ) | 2 | — | 1 | ||||||||||||||
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
FirstEnergy has pre-tax net operating loss carryforwards for state and local income tax purposes of approximately $1.6 billion, of which $724 million is expected to be utilized. The associated deferred tax assets are $20 million. These losses expire as follows:
| Expiration Period | FE | FES | Penelec | |||||||||
| (In millions) | ||||||||||||
| 2011-2015 | $ | 532 | $ | 321 | $ | — | ||||||
| 2016-2020 | 112 | 15 | 14 | |||||||||
| 2021-2025 | 480 | 4 | 186 | |||||||||
| 2026-2030 | 524 | 230 | 150 | |||||||||
| $ | 1,648 | $ | 570 | $ | 350 | |||||||
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General Taxes
Details of general taxes for the three years ended December 31, 2010 are shown below:
| FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
2010 | ||||||||||||||||||||||||||||||||
| Kilowatt-hour excise | $ | 245 | $ | 5 | $ | 92 | $ | 68 | $ | 27 | $ | 51 | $ | — | $ | — | ||||||||||||||||
| State gross receipts | 185 | 17 | 15 | — | — | — | 85 | 68 | ||||||||||||||||||||||||
| Real and personal property | 243 | 53 | 67 | 70 | 23 | 5 | — | (1 | ) | |||||||||||||||||||||||
| Social security and unemployment | 86 | 14 | 8 | 5 | 2 | 9 | 4 | 5 | ||||||||||||||||||||||||
| Other | 17 | 5 | 1 | — | — | — | (1 | ) | 1 | |||||||||||||||||||||||
| Total general taxes | $ | 776 | $ | 94 | $ | 183 | $ | 143 | $ | 52 | $ | 65 | $ | 88 | $ | 73 | ||||||||||||||||
2009 | ||||||||||||||||||||||||||||||||
Kilowatt-hour excise(1) | $ | 224 | $ | 1 | $ | 84 | $ | 66 | $ | 24 | $ | 49 | $ | — | $ | — | ||||||||||||||||
| State gross receipts | 171 | 14 | 15 | — | — | — | 78 | 63 | ||||||||||||||||||||||||
| Real and personal property | 253 | 53 | 64 | 74 | 21 | 5 | 2 | 2 | ||||||||||||||||||||||||
| Social security and unemployment | 90 | 14 | 8 | 5 | 3 | 9 | 5 | 6 | ||||||||||||||||||||||||
| Other | 15 | 5 | — | — | — | — | 3 | 3 | ||||||||||||||||||||||||
| Total general taxes | $ | 753 | $ | 87 | $ | 171 | $ | 145 | $ | 48 | $ | 63 | $ | 88 | $ | 74 | ||||||||||||||||
2008 | ||||||||||||||||||||||||||||||||
| Kilowatt-hour excise | $ | 249 | $ | 1 | $ | 97 | $ | 70 | $ | 30 | $ | 51 | $ | — | $ | — | ||||||||||||||||
| State gross receipts | 183 | 16 | 17 | — | — | — | 79 | 70 | ||||||||||||||||||||||||
| Real and personal property | 240 | 53 | 61 | 67 | 19 | 5 | 3 | 2 | ||||||||||||||||||||||||
| Social security and unemployment | 95 | 14 | 9 | 6 | 3 | 10 | 5 | 6 | ||||||||||||||||||||||||
| Other | 11 | 4 | 2 | — | — | 1 | (1 | ) | 2 | |||||||||||||||||||||||
| Total general taxes | $ | 778 | $ | 88 | $ | 186 | $ | 143 | $ | 52 | $ | 67 | $ | 86 | $ | 80 | ||||||||||||||||
| (1) | Kilowatt-hour excise tax for OE and TE includes a $7.1 million and $3.5 million adjustment, respectively, recognized in 2009 related to prior periods. |
10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
Federally-enforceable mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC and ATSI. The NERC, as the ERO is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.
FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirstand the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
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On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up to eleven hours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.
On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirstissued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirston September 27, 2010. At this time, FirstEnergy is unable to predict the outcome of this investigation.
(B) OHIO
The Ohio Companies operate under an ESP, which expires on May 31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies to collect a delivery service improvement rider (Rider DSI) at an overall average rate of $0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Ohio Companies currently purchase generation at the average wholesale rate of a CBP conducted in May 2009. FES is one of the suppliers to the Ohio Companies through the May 2009 CBP. The PUCO approved a $136.6 million distribution rate increase for the Ohio Companies in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). Applications for rehearing of the PUCO order in the distribution case were filed by the Ohio Companies and one other party. The Ohio Companies raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the level of rate of return and the amount of general plant balances. On February 2, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing filed both by the Ohio Companies and by the other party.
On March 23, 2010, the Ohio Companies filed an application for a new ESP. The new ESP will go into effect on June 1, 2011 and conclude on May 31, 2014. The PUCO approved the new ESP on August 25, 2010 with certain modifications. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (initial auctions scheduled for October 20, 2010 and January 25, 2011); no increase in base distribution rates through May 31, 2014; a load cap of no less than 80%, which also applies to any tranches assigned post auction; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. Rider DCR substitutes for Rider DSI which terminates under the current ESP. The Ohio Companies also agreed not to pay certain costs related to the companies’ integration into PJM, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, established a $12 million fund to assist low income customers over the term of the ESP, and agreed to additional energy efficiency benefits. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the integration into PJM. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On September 24, 2010, an application for rehearing was filed by the OCC and two other parties. On February 9, 2011, the PUCO issued an Entry on Rehearing denying the applications for rehearing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
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On December 15, 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO, which is delaying the launch of the programs described in the plan. As a result, the Ohio Companies filed on January 11, 2011, a request for amendment of OE’s 2010 energy efficiency and peak demand reduction benchmarks to levels actually achieved in 2010. Because the Commission indicated that it would revise all of the Ohio Companies’ 2010, 2011, and 2012 benchmarks when addressing the Ohio Companies’ three year portfolio plan, and an order has yet to be issued on that plan, CEI and TE also requested a waiver of their respective yet-to-be defined 2010 energy efficiency benchmarks if and only to the degree one is deemed necessary to bring these companies into compliance with their 2010 energy efficiency obligations. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RFPs sought RECs, including solar RECs and RECs generated in Ohio in order to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2009, 2010 and 2011. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark, which application is still pending. In July 2010, the Ohio Companies initiated an additional RFP to secure RECs and solar RECs needed to meet the Ohio Companies’ alternative energy requirements as set forth in SB221 for 2010 and 2011. As a result of this RFP, contracts were executed in August 2010. On January 11, 2011, the Ohio Companies filed an application with the PUCO seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio due to the insufficient quantity of solar energy resources reasonably available in the market. The PUCO has not yet ruled on that application.
On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010, and the proceeding remains open. The hearing in the matter is set to commence on February 16, 2011.
(C) PENNSYLVANIA
The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. On March 18, 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. By Order entered March 25, 2010, the PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate increases commencing January 1, 2011. The PPUC approved this plan on June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $252.7 million ($188.0 million for Met-Ed and $64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. The argument before the Commonwealth Court,en banc, was held on December 8, 2010.
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On May 20, 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers was increased to provide for full recovery by December 31, 2010.
Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply with a staggered procurement schedule that varies by customer class, using a descending clock auction. On August 12, 2009, the parties to the proceeding filed a settlement agreement of all but two issues, and the PPUC entered an Order approving the settlement and the generation procurement plan on November 6, 2009. Generation procurement began in January 2010.
On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. On July 29, 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.
Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC on August 14, 2009. This plan proposed a 24-month assessment period in which the Pennsylvania Companies will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. On April 15, 2010, the PPUC adopted a Motion by Chairman Cawley that modified the ALJ’s initial decision, and decided various issues regarding the SMIP for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates. On August 5, 2010, the PPUC granted in part the petition for reconsideration by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.
(D) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of December 31, 2010, the accumulated deferred cost balance was a credit of approximately $37 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. On February 10, 2011, the NJBPU approved a stipulation which allows the change in rates to become effective March 1, 2011.
On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). This matter is currently pending before the NJBPU.
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New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by New Jersey electric and gas utilities in order to achieve the goals of the EMP. On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to submit Utility Master Plans until such time as the status of the EMP has been made clear. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.
(E) FERC MATTERS
Rates for Transmission Service Between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, the FERC set the SECA for hearing. The presiding ALJ issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by the FERC. On May 21, 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC on November 23, 2010, and the relevant payments made. Rehearings remain pending in this proceeding.
PJM Transmission Rate
On April 19, 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.
The FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision on August 6, 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.
In an order dated January 21, 2010, FERC set the matter for “paper hearings”— meaning that FERC called for parties to submit comments or written testimony pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is expected to act by May 31, 2011.
RTO Realignment
On December 17, 2009, FERC issued an order approving, subject to certain future compliance filings, ATSI’s withdrawal from MISO and integration into PJM. This move, which is expected to be effective on June 1, 2011, allows FirstEnergy to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The realignment will make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. In the order, FERC approved FirstEnergy’s proposal to use a FRR Plan to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.
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FirstEnergy successfully conducted the FRR auctions on March 19, 2010. Moreover, the ATSI zone loads participated in the PJM base residual auction for the 2013 delivery year. Successful completion of these steps secured the capacity necessary for the ATSI footprint to meet PJM’s capacity requirements. On August 25, 2010, the PUCO issued an order in the 2010 ESP Case approving a settlement that, among other things, called for the PUCO to withdraw its opposition to the RTO consolidation. In addition, the order approved a wholesale procurement process, and certain “retail choice” policies, that reflected ATSI’s entry into PJM on June 1, 2011.
On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. FirstEnergy expects ATSI to enter PJM on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to start charging its proposed rates, subject to refund. Additional FERC proceedings are either pending or expected in which the amount of exit fees, transmission cost allocations, and costs associated with long term firm transmission rights payable by the ATSI zone upon its withdrawal from the Midwest ISO will be determined. In addition, certain parties may protest other aspects of ATSI’s integration into PJM, and certain of these matters remain outstanding and will be resolved in future FERC proceedings. The outcome of these proceedings cannot be predicted.
MISO Multi-Value Project Rule Proposal
On July 15, 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs—are a class of MTEP projects. The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the anticipated June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $11 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
On September 10, 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVP projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
On December 16, 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attach prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, the Company argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time.
Sales to Affiliates
FES has received authorization from FERC to make wholesale power sales to the Utilities. FES actively participates in auctions conducted by or on behalf of the Utilities to obtain the power and related services necessary to meet the Utilities’ POLR obligations. Because of the merger with FirstEnergy, AS is considered an affiliate of the Utilities for purposes of FERC’s affiliate restriction regulations. This requires AS to obtain prior FERC authorization to make sales to the Utilities when it successfully participates in the Utilities’ POLR auctions.
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FES currently supplies the Ohio Companies with a portion of their capacity, energy, ancillary services and transmission under a Master SSO Supply Agreement for a two-year period ending May 31, 2011. FES won 51 tranches in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International on May 13-14, 2009. Other winning suppliers have assigned their Master SSO Supply Agreements to FES, five of which were effective in June, two more in July, four more in August and ten more in September, 2009. FES also supplies power used by Constellation to serve an additional five tranches. As a result of these arrangements, FES serves 77 tranches, or 77% of the POLR load of the Ohio Companies until May 31, 2011.
On October 20, 2010, FES participated in a descending clock auction for POLR service administered by the Ohio Companies and their consultant, CRA International, for the following periods: June 1, 2011 through May 31, 2012; June 1, 2011, through May 31, 2013; and June 1, 2010 through May 31, 2014. The Ohio Companies offered 17, 17, and 16 tranches for these periods, respectively. FES won 10, 7, and 3 tranches, respectively, for these periods. On January 25, 2011, the Ohio Companies conducted a second auction offering the same product for identical time periods. FES won 3, 0, and 3 tranches, respectively, for these periods. FES entered into a Master SSO Supply Agreement to provide capacity, energy, ancillary services, and congestion costs to the Ohio Companies for the tranches won. Under the ESP in effect for these time periods, the Ohio Companies are responsible for payment of noncontrollable transmission costs billed by PJM for POLR service.
On October 18, 2010, FES participated in a descending clock auction for POLR service administered by both Met-Ed and Penelec and their consultant, National Economic Research Associates (NERA) for the following tranche products and delivery periods: Residential 5-month, Residential 24-month, Commercial 5-month, Commercial 12-month and Industrial 12-month. All 5-month delivery periods are from January 1, 2011 through May 31, 2011, all 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 7 Residential 5-month tranches, 4 Residential 24-month tranches, 6 Commercial 5-month tranches, 6 Commercial 12-month tranches and 1 Industrial tranche while Penelec offered 5 Residential 5-month tranches, 3 Residential 24-month tranches, 5 Commercial 5-month tranches, 5 Commercial 12-month tranches and 1 Industrial tranche.
For Met-Ed offerings, FES won 4 Residential 5-month tranches, 2 Residential 24-month tranches, 1 Commercial 5-month tranche, 1 Commercial 12-month tranche and zero Industrial tranches. For Penelec offerings, FES won 1 Residential 5-month tranche, 1 Residential 24-month tranche, zero Commercial 5-month tranches, zero Commercial 12-month tranches and zero Industrial tranches. FES entered into separate Supplier Master Agreements (SMA) to provide capacity, energy, ancillary services, and congestion costs with Met-Ed and Penelec for each product won. Under the terms and conditions of the SMA, Met-Ed and Penelec are responsible for payment of noncontrollable transmission costs billed by PJM.
On January 18 to 20, 2011 FES participated in a descending clock auction for POLR service administered by Met-Ed, Penelec, and Penn Power and their consultant, NERA for the following tranche products and delivery periods: Residential 12-month, Residential 24-month, Commercial 12-month and Industrial 12-month. All 12-month delivery periods are from June 1, 2011 through May 31, 2012 while all 24-month delivery periods are from June 1, 2011 through May 31, 2013. Met-Ed offered 3 Residential 12-month tranches, 4 Residential 24-month tranches, 6 Commercial 12-month tranches and 11 Industrial tranches. Penelec offered 3 Residential 12-month tranches, 2 Residential 24-month tranches, 5 Commercial 12-month tranches and 11 Industrial tranches. Penn Power offered 2 Residential 12-month tranches, 1 Residential 24-month tranche, 3 Commercial 12-month tranches and 3 Industrial tranches.
For Met-Ed offerings, FES won 1 Commercial 12-month tranche and zero for the remaining products. For Penelec and Penn Power offerings, FES won no tranches. FES entered into a SMA to provide capacity, energy, ancillary services, and congestion costs with Met-Ed for the product won. Under the terms and conditions of the SMA, Met-Ed is responsible for payment of noncontrollable transmission costs billed by PJM.
11. CAPITALIZATION
(A) COMMON STOCK
Retained Earnings and Dividends
As of December 31, 2010, FirstEnergy’s unrestricted retained earnings were $4.6 billion. Dividends declared in 2010 and 2009 were $2.20 per share in each year, which included quarterly dividends of $0.55 per share paid in the second, third and fourth quarters of 2010 and 2009, respectively, and payable in the first quarter of 2011 and 2010, respectively. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors.
In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as its equity to total capitalization ratio (without consideration of retained earnings) remains above 35%. The articles of incorporation, indentures and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ ability to pay cash dividends to FirstEnergy as of December 31, 2010.
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(B) PREFERRED AND PREFERENCE STOCK
FirstEnergy’s and the Utilities’ preferred stock and preference stock authorizations are as follows:
| Preferred Stock | Preference Stock | |||||||||||||||
| Shares | Par | Shares | Par | |||||||||||||
| Authorized | Value | Authorized | Value | |||||||||||||
| FirstEnergy | 5,000,000 | $ | 100 | |||||||||||||
| OE | 6,000,000 | $ | 100 | 8,000,000 | no par | |||||||||||
| OE | 8,000,000 | $ | 25 | |||||||||||||
| Penn | 1,200,000 | $ | 100 | |||||||||||||
| CEI | 4,000,000 | no par | 3,000,000 | no par | ||||||||||||
| TE | 3,000,000 | $ | 100 | 5,000,000 | $ | 25 | ||||||||||
| TE | 12,000,000 | $ | 25 | |||||||||||||
| JCP&L | 15,600,000 | no par | ||||||||||||||
| Met-Ed | 10,000,000 | no par | ||||||||||||||
| Penelec | 11,435,000 | no par | ||||||||||||||
No preferred shares or preference shares are currently outstanding.
(C) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS
The following table presents the outstanding consolidated long-term debt and other long-term obligations of FirstEnergy as of December 31, 2010 and 2009:
| Weighted Average | December 31, | |||||||||||
| Interest Rate (%) | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| FMBs: | ||||||||||||
| Due 2010-2013 | 9.74 | $ | 3 | $ | 28 | |||||||
| Due 2014-2018 | 8.84 | 330 | 330 | |||||||||
| Due 2019-2023 | 6.13 | 101 | 107 | |||||||||
| Due 2024-2028 | 8.75 | 314 | 314 | |||||||||
| Due 2038 | 8.25 | 275 | 275 | |||||||||
| Total FMBs | 1,023 | 1,054 | ||||||||||
| Secured Notes | ||||||||||||
| Due 2010-2013 | 4.46 | 732 | 456 | |||||||||
| Due 2014-2018 | 6.87 | 638 | 777 | |||||||||
| Due 2019-2023 | 5.60 | 622 | 481 | |||||||||
| Due 2029-2033 | 5.41 | 276 | 510 | |||||||||
| Due 2034-2038 | 4.13 | 459 | 322 | |||||||||
| Due 2041 | 0.30 | 57 | 57 | |||||||||
| Total Secured Notes | 2,784 | 2,603 | ||||||||||
| Unsecured Notes: | ||||||||||||
| Due 2010-2013 | 5.80 | 712 | 878 | |||||||||
| Due 2014-2018 | 5.43 | 2,467 | 2,473 | |||||||||
| Due 2019-2023 | 5.72 | 2,435 | 2,435 | |||||||||
| Due 2024-2028 | 3.95 | 65 | 65 | |||||||||
| Due 2029-2033 | 6.25 | 1,971 | 1,737 | |||||||||
| Due 2034-2038 | 5.47 | 1,727 | 1,864 | |||||||||
| Due 2039-2043 | 5.25 | 698 | 698 | |||||||||
| Due 2047 | 3.00 | 46 | 46 | |||||||||
| Total Unsecured Notes | 10,121 | 10,196 | ||||||||||
| Capital lease obligations | 54 | 13 | ||||||||||
| Net unamortized premium (discount) on debt | 83 | (24 | ) | |||||||||
| Long-term debt due within one year | (1,486 | ) | (1,834 | ) | ||||||||
| Total long-term debt and other long term obligations | $ | 12,579 | $ | 12,008 | ||||||||
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Securitized Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the accounts of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.
JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. As of December 31, 2010, $310 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate annual servicing fees of up to $628,000 that are payable from TBC collections.
Other Long-term Debt
FGCO, NGC and each of the Utilities, except for JCP&L and Penelec, have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property.
FirstEnergy and its subsidiaries have various debt covenants under their respective financing arrangements. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on debt and the maintenance of certain financial ratios. There also exist cross-default provisions in a number of the respective financing arrangements of FirstEnergy, FES, FGCO, NGC and the Utilities. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries defaults under another financing arrangement of a certain principal amount, typically $50 million. Although such defaults by any of the Utilities will generally cross-default FirstEnergy financing arrangements containing these provisions, defaults by FirstEnergy will not generally cross-default applicable financing arrangements of any of the Utilities. Defaults by any of FES, FGCO or NGC will generally cross-default to applicable financing arrangements of FirstEnergy and, due to the existence of guarantees of FirstEnergy of certain financing arrangements of FES, FGCO and NGC, defaults by FirstEnergy will generally cross-default FES, FGCO and NGC financing arrangements containing these provisions. Cross-default provisions are not typically found in any of the senior note or FMBs of FirstEnergy or the Utilities.
Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2010, the Utilities’ annual sinking fund requirement for all FMB issued under the various mortgage indentures amounted to payments of $36 million (Penn — $7 million, Met-Ed — $8 million, and Penelec — $21 million) in 2010. Penn expects to meet its 2011 annual sinking fund requirement with a replacement credit under its mortgage indenture. Met-Ed can fulfill its sinking fund obligation by providing bondable property additions, previously retired FMBs or cash to the respective mortgage bond trustees. Since Penelec’s first mortgage bond indenture was terminated in 2010, Penelec no longer has a sinking fund obligation.
As of December 31, 2010, FirstEnergy’s currently payable long-term debt includes approximately $827 million (FES — $778 million, Met-Ed — $29 million and Penelec — $20 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds, or if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
On August 20, 2010, FES completed the remarketing of $250 million of PCRBs. Of the $250 million, $235 million of PCRBs were converted from a variable interest rate to a fixed interest rate. The remaining $15 million of PCRBs continue to bear a fixed interest rate. The interest rate conversion minimizes financial risk by converting the long-term debt into a fixed rate and, as a result, reducing exposure to variable interest rates over the short-term. These remarketings included two series: $235 million of PCRBs that now bears a per-annum rate of 2.25% and is subject to mandatory purchase on June 3, 2013; and $15 million of PCRBs that now bears a per-annum rate of 1.5% and is subject to mandatory purchase on June 1, 2011.
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On October 1, 2010, FES completed the refinancing and remarketing of six series of PCRBs totaling $313 million. These PCRBs were converted from a variable interest rate to a fixed long term interest rate of 3.375% per annum and are subject to mandatory purchase on July 1, 2015.
On December 3, 2010, FES completed the remarketing of four series of PCRBs totaling $153 million and Penelec completed the remarketing of one $25 million PCRB. These PCRBs were converted from a variable interest rate to fixed interest rates ranging from 2.25% to 3.75% per annum.
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years are:
| Year | FE | FES | OE | CEI | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
| 2011 | $ | 445 | $ | 163 | $ | 1 | $ | 20 | $ | 32 | $ | — | $ | — | ||||||||||||||
| 2012 | 448 | 68 | 1 | 22 | 34 | — | — | |||||||||||||||||||||
| 2013 | 554 | 75 | 1 | 324 | 36 | 150 | — | |||||||||||||||||||||
| 2014 | 529 | 99 | 1 | 26 | 38 | 250 | 150 | |||||||||||||||||||||
| 2015 | 639 | 450 | 151 | 24 | 41 | — | — | |||||||||||||||||||||
The following table classifies the outstanding PCRBs by year, for the next three years, representing the next time the debt holders may exercise their right to tender their PCRBs.
| Year | FE | FES | Met-Ed | Penelec | ||||||||||||
| (In millions) | ||||||||||||||||
| 2011 | $ | 1,043 | $ | 969 | $ | 29 | $ | 45 | ||||||||
| 2012 | 270 | 270 | — | — | ||||||||||||
| 2013 | 235 | 235 | — | — | ||||||||||||
Obligations to repay certain PCRBs are secured by several series of FMBs. Certain PCRBs are entitled to the benefit of irrevocable bank LOCs of $835 million as of December 31, 2010, or noncancelable municipal bond insurance of $14 million as of December 31, 2010, to pay principal of, or interest on, the applicable PCRBs. To the extent that drawings are made under the LOCs or the insurance, FGCO, NGC and the Utilities are entitled to a credit against their obligation to repay those bonds. FGCO, NGC and the Utilities pay annual fees of 0.35% to 3.30% of the amounts of the LOCs to the issuing banks and are obligated to reimburse the banks or insurers, as the case may be, for any drawings thereunder. The insurers hold FMBs as security for such reimbursement obligations. OE has LOCs of $130 million and $42 million in connection with the sale and leaseback of Beaver Valley Unit 2 and Perry Unit 1, respectively. The amounts and annual fees for FirstEnergy, FES and the Utilities are as follows:
| FE | FES | Met-Ed | Penelec | |||||||||||||
| (In millions) | ||||||||||||||||
Amounts | ||||||||||||||||
| LOCs | $ | 835 | $ | 786 | $ | 29 | $ | 20 | ||||||||
| Insurance Policies | 14 | — | 14 | — | ||||||||||||
Annual Fee | ||||||||||||||||
| LOCs | 0.35% to 3.30 | % | 0.35% to 3.30 | % | 1.60 | % | 1.60 | % | ||||||||
12. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES and the Utilities use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.
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FirstEnergy, FES and the Utilities maintain nuclear decommissioning trust funds that are legally restricted for purposes of settling the nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2010 and 2009 were as follows:
| 2010 | 2009 | |||||||
| (In millions) | ||||||||
| FE | $ | 1,973 | $ | 1,859 | ||||
| FES | 1,146 | 1,089 | ||||||
| OE | 127 | 121 | ||||||
| TE | 76 | 74 | ||||||
| JCP&L | 182 | 167 | ||||||
| Met-Ed | 289 | 266 | ||||||
| Penelec | 153 | 143 | ||||||
Accounting standards for conditional retirement obligations associated with tangible long-lived assets require recognition of the fair value of a liability for an ARO in the period in which it is incurred if a reasonable estimate can made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not in the recognition of the liability.
The following table summarizes the changes to the ARO balances during 2010 and 2009.
| ARO Reconciliation | FE | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | ||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
| Balance, January 1, 2009 | $ | 1,347 | $ | 863 | $ | 92 | $ | 2 | $ | 30 | $ | 95 | $ | 171 | $ | 87 | ||||||||||||||||
| Liabilities incurred | 4 | 1 | — | — | — | — | — | — | ||||||||||||||||||||||||
| Liabilities settled | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Accretion | 90 | 58 | 6 | — | 2 | 7 | 11 | 6 | ||||||||||||||||||||||||
| Revisions in estimated cash flows | (16 | ) | (1 | ) | (12 | ) | — | — | — | (2 | ) | (1 | ) | |||||||||||||||||||
| Balance, December 31, 2009 | 1,425 | 921 | 86 | 2 | 32 | 102 | 180 | 92 | ||||||||||||||||||||||||
| Liabilities incurred | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||
| Liabilities settled | (11 | ) | — | (10 | ) | — | — | — | — | — | ||||||||||||||||||||||
| Accretion | 93 | 59 | 5 | — | 2 | 6 | 13 | 6 | ||||||||||||||||||||||||
Revisions in estimated cash flows (1) | (100 | ) | (88 | ) | (7 | ) | — | (5 | ) | — | — | — | ||||||||||||||||||||
| Balance, December 31, 2010 | $ | 1,407 | $ | 892 | $ | 74 | $ | 2 | $ | 29 | $ | 108 | $ | 193 | $ | 98 | ||||||||||||||||
| (1) | During the second quarter of 2010, studies were completed to reassess the estimated cost of decommissioning the Beaver Valley nuclear generating facilities. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES, OE and TE and reduced the liability for each subsidiary in the amounts of $88 million, $7 million, and $5 million, respectively. |
13. SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT
FirstEnergy had approximately $700 million of short-term indebtedness as of December 31, 2010, comprised of borrowings under a $2.75 billion revolving line of credit. Total short-term bank lines of committed credit to FirstEnergy and the Utilities as of January 31, 2011 were approximately $3.2 billion of which $2.5 billion was unused and available.
FirstEnergy, along with certain of its subsidiaries, are parties to a $2.75 billion five-year revolving credit facility. FirstEnergy has the ability to request an increase in the total commitments available under this facility up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations. The annual facility fee is 0.125%.
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The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of December 31, 2010:
| Revolving | Regulatory and | |||||||
| Credit Facility | Other Short-Term | |||||||
| Borrower | Sub-Limit | Debt Limitations | ||||||
| (in millions) | ||||||||
FirstEnergy | $ | 2,750 | $ | — | (1) | |||
FES | 1,000 | — | (1) | |||||
OE | 500 | 500 | ||||||
Penn | 50 | 34 | (2) | |||||
CEI | 250 | (3) | 500 | |||||
TE | 250 | (3) | 500 | |||||
JCP&L | 425 | 411 | (2) | |||||
Met-Ed | 250 | 300 | (2) | |||||
Penelec | 250 | 300 | (2) | |||||
ATSI | 50 | (4) | 100 | |||||
| (1) | No regulatory approvals, statutory or charter limitations applicable. | |
| (2) | Excluding amounts which may be borrowed under the regulated companies’ money pool. | |
| (3) | Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. | |
| (4) | The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that ATSI has received regulatory approval to have short-term borrowings up to the same amount. |
The regulated companies also have the ability to borrow from each other and FirstEnergy to meet their short-term working capital requirements. A similar but separate arrangement exists among the unregulated companies. FESC administers these two money pools and tracks FirstEnergy’s surplus funds and those of the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in 2010 was 0.51% for the regulated companies’ money pool and 0.60% for the unregulated companies’ money pool.
The weighted average interest rates on short-term borrowings outstanding as of December 31, 2010 and 2009 were as follows:
| 2010 | 2009 | |||||||
| FE | 0.68 | % | 0.74 | % | ||||
| FES | 0.60 | % | 1.84 | % | ||||
| OE | 0.51 | % | 0.72 | % | ||||
| CEI | 1.92 | % | 1.13 | % | ||||
| TE | — | 0.72 | % | |||||
| JCP&L | — | — | ||||||
| Met-Ed | 0.51 | % | — | |||||
| Penelec | 0.51 | % | 0.72 | % | ||||
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As of December 31, 2010, FirstEnergy Corp. had four receivables securitizations for five of its seven public utilities. These transactions enable the company to access up to $395 million of financing at costs based on commercial paper rates plus annual fees. Each of the facilities matures in 364 days, and are reflected in the table below. In March of 2011 the Centerior Funding Corp. and OES Capital facilities are scheduled to decrease to $100 million each. There were no outstanding borrowings as of December 31, 2010.
| Parent | Annual | |||||||||||
| Subsidiary Company | Company | Commitment | Facility Fee | Maturity | ||||||||
| (In millions) | ||||||||||||
| OES Capital, Incorporated | OE | $ | 125 | 1.08 | % | March 30, 2011 | ||||||
| Centerior Funding Corporation | CEI | 125 | 1.00 | March 30, 2011 | ||||||||
| Met-Ed Funding LLC | Met-Ed | 75 | 0.51 | June 17, 2011 | ||||||||
| Penelec Funding LLC | Penelec | 70 | 0.51 | June 17, 2011 | ||||||||
| $ | 395 | |||||||||||
14. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) NUCLEAR INSURANCE
The Price-Anderson Act limits the public liability which can be assessed with respect to a nuclear power plant to $12.6 billion (assuming 104 units licensed to operate) for a single nuclear incident, which amount is covered by: (i) private insurance amounting to $375 million; and (ii) $12.2 billion provided by an industry retrospective rating plan required by the NRC pursuant thereto. Under such retrospective rating plan, in the event of a nuclear incident at any unit in the United States resulting in losses in excess of private insurance, up to $118 million (but not more than $18 million per unit per year in the event of more than one incident) must be contributed for each nuclear unit licensed to operate in the country by the licensees thereof to cover liabilities arising out of the incident. Based on their present nuclear ownership and leasehold interests, FirstEnergy’s maximum potential assessment under these provisions would be $470 million (OE-$40 million, NGC-$408 million, and TE-$22 million) per incident but not more than $70 million (OE-$6 million, NGC-$61 million, and TE-$3 million) in any one year for each incident.
In addition to the public liability insurance provided pursuant to the Price-Anderson Act, FirstEnergy has also obtained insurance coverage in limited amounts for economic loss and property damage arising out of nuclear incidents. FirstEnergy is a member of NEIL which provides coverage (NEIL I) for the extra expense of replacement power incurred due to prolonged accidental outages of nuclear units. Under NEIL I, FirstEnergy’s subsidiaries have policies, renewable yearly, corresponding to their respective nuclear interests, which provide an aggregate indemnity of up to approximately $1.4 billion (OE-$120 million, NGC-$1.22 billion, TE-$64 million) for replacement power costs incurred during an outage after an initial 26-week waiting period. Members of NEIL I pay annual premiums and are subject to assessments if losses exceed the accumulated funds available to the insurer. FirstEnergy’s present maximum aggregate assessment for incidents at any covered nuclear facility occurring during a policy year would be approximately $9 million (OE-$1 million, NGC-$8 million, and TE-less than $1 million).
FirstEnergy is insured as to its respective nuclear interests under property damage insurance provided by NEIL to the operating company for each plant. Under these arrangements, up to $2.8 billion of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. FirstEnergy pays annual premiums for this coverage and is liable for retrospective assessments of up to approximately $61 million (OE-$5 million, NGC-$52 million, TE-$2 million, Met Ed, Penelec, and JCP&L-less than $1 million each) during a policy year.
FirstEnergy intends to maintain insurance against nuclear risks as described above as long as it is available. To the extent that replacement power, property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of FirstEnergy’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by FirstEnergy’s insurance policies, or to the extent such insurance becomes unavailable in the future, FirstEnergy would remain at risk for such costs.
The NRC requires nuclear power plant licensees to obtain minimum property insurance coverage of $1.1 billion or the amount generally available from private sources, whichever is less. The proceeds of this insurance are required to be used first to ensure that the licensed reactor is in a safe and stable condition and can be maintained in that condition to prevent any significant risk to the public health and safety. Within 30 days of stabilization, the licensee is required to prepare and submit to the NRC a cleanup plan for approval. The plan is required to identify all cleanup operations necessary to decontaminate the reactor sufficiently to permit the resumption of operations or to commence decommissioning. Any property insurance proceeds not already expended to place the reactor in a safe and stable condition must be used first to complete those decontamination operations that are ordered by the NRC. FirstEnergy is unable to predict what effect these requirements may have on the availability of insurance proceeds.
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(B) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of December 31, 2010, outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting primarily of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.5 billion), surety bonds and LOCs ($0.4 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.3 billion (included in the $0.8 billion discussed above) as of December 31, 2010 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of December 31, 2010, FirstEnergy’s maximum exposure under these collateral provisions was $468 million, consisting of $429 million due to a below investment grade credit rating (of which $224 million is due to an acceleration of payment or funding obligation) and $39 million due to “material adverse event” contractual clauses. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to $532 million, consisting of $486 million due to a below investment grade credit rating (of which $224 million is related to an acceleration of payment or funding obligation) and $46 million due to “material adverse event” contractual clauses.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $82 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of December 31, 2010, and forward prices as of that date, FES has posted collateral of $185 million. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one year time horizon), FES would be required to post an additional $28 million. Depending on the volume of forward contracts and future price movements, FES could be required to post higher amounts for margining.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in an amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
On October 22, 2010, Signal Peak and Global Rail entered into a $350 million syndicated two-year senior secured term loan facility among the two limited liability companies that comprise Signal Peak and Global Rail, as borrowers. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership with FEV, the borrowers have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the banks as collateral for the facility.
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(C) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) under the CAA by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
The Sammis, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NOx and SO2 emissions through the installation of pollution control devices or repowering. OE and Penn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement.
In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in those three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy.
In January 2009, the EPA issued a NOV to GenOn alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986 and also alleged NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of the Keystone Station, and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that “modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification that was required 60 days prior to filing a citizen suit under the CAA. In January, 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on alleged “modifications” at the Homer City Power Station between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the State of New York intervened and have filed a separate complaint regarding the Homer City Station. Mission Energy Westside, Inc. is seeking indemnification from Penelec, the co-owner and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy Westside, Inc. is under dispute and Penelec is unable to predict the outcome of this matter.
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In January 2011, a complaint was filed against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’s air emissions. The complaint was also filed against the former co-owner, NYSEG and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. The complaint also seeks certification as a class action and to enjoin the Homer City Station from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint.
In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR, and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2010, the EPA proposed the CATR to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.6 million tons annually and NOx emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NOx and SO2 emission allowances between power plants located in the same state and severely limits interstate trading of NOx and SO2 emission allowances. The EPA also requested comment on two alternative approaches—the first eliminates interstate trading of NOx and SO2 emission allowances and the second eliminates trading of NOx and SO2 emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below and any future regulations that are ultimately implemented, FGCO’s future cost of compliance may be substantial. Management continues to assess the impact of these environmental proposals and other factors on FGCO’s facilities, particularly on the operation of its smaller, non-supercritical units. In August 2010, for example, management decided to idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
The EPA’s CAMR provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping nationwide emissions of mercury at 38 tons by 2010 (as a “co-benefit” from implementation of SO2 and NOx emission caps under the EPA’s CAIR program) and 15 tons per year by 2018. The U.S. Court of Appeals for the District of Columbia, at the urging of several states and environmental groups, vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. On April 29, 2010, the EPA issued proposed MACT regulations requiring emissions reductions of mercury and other hazardous air pollutants from non-electric generating unit boilers. If finalized, the non-electric generating unit MACT regulations could also provide precedent for MACT standards applicable to electric generating units. On January 20, 2011, the U.S. District Court for the District of Columbia denied a motion by the EPA for an extension of the deadline to issue final rules, ordering the EPA to issue such rules by February 21, 2011. The EPA also entered into a consent decree requiring it to propose MACT regulations for mercury and other hazardous air pollutants from electric generating units by March 16, 2011, and to finalize the regulations by November 16, 2011. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.
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Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the CAA’s PSD program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.
At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement which recognized the scientific view that the increase in global temperature should be below two degrees Celsius; include a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establish the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. Once they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. On December 6, 2010, the U.S. Supreme Court granted a writ of certiorari to the Second Circuit inConnecticut v. AEP. Briefing and oral argument are expected to be completed in early 2011 and a decision issued in or around June 2011. While FirstEnergy is not a party to this litigation, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy’s operations.
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The EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’s cooling water system). The EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On November 19, 2010, the Ohio EPA issued a permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In June 2008, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
On December 30, 2009, in an advanced notice of public rulemaking, the EPA said that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. On May 4, 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FGCO’s future cost of compliance with any coal combustion residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of December 31, 2010, based on estimates of the total costs of cleanup, the Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $32 million) have been accrued through December 31, 2010. Included in the total are accrued liabilities of approximately $64 million for environmental remediation of former MGPs and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(D) OTHER LEGAL PROCEEDINGS
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L’s territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. JCP&L is waiting for the Court’s decision.
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Litigation Relating to the Proposed Allegheny Merger
In connection with the proposed merger (Note 22), purported shareholders of Allegheny have filed putative shareholder class action and/or derivative lawsuits against Allegheny and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland (Maryland Court). One was withdrawn. The Maryland Court has consolidated the remaining three cases under the caption: In re Allegheny Energy Shareholder and Derivative Litigation, C.A. No. 24-C-10-1301. Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania and the court has consolidated these actions under the caption: In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010. One putative shareholder class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captioned Louisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. In summary, the lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of all these shareholder lawsuits and have reached agreement with counsel for all of the plaintiffs concerning fee applications. Under the terms of the settlement, no payments are being made by FirstEnergy or Merger Sub. A formal stipulation of settlement was filed with the Maryland Court on October 18, 2010 and it was approved and became final on January 12, 2011. The separate Pennsylvania federal and state proceedings were dismissed on January 14, 2011 and January 18, 2011, respectively. The above shareholder actions have been fully and finally resolved.
Nuclear Plant Matters
During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the CRDM nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking, further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service. On September 9, 2010, the NRC held a public exit meeting describing the results of the NRC special inspection team inspection of FENOC’s identification of the CRDM nozzles with flaws and the modifications to those nozzles. On October 22, 2010, the NRC issued its final report of the special inspection. The report contained three findings characterized as very low safety significance that were promptly corrected prior to plant operation.
On April 5, 2010, the Union of Concerned Scientists (UCS) requested that the NRC issue a Show Cause Order, or otherwise delay the restart of the Davis-Besse Nuclear Power Station until the NRC determines that adequate protection standards have been met and reasonable assurance exists that these standards will continue to be met after the plant’s operation is resumed. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any, that the NRC takes in response to the UCS request have not been determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of December 31, 2010, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. FirstEnergy provides an additional $15 million parental guarantee associated with the funding of decommissioning costs for these units. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and its effects on particular businesses and the economy could also affect the values of the nuclear decommissioning trusts. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated the decommissioning of FirstEnergy’s nuclear facilities. As a result, FirstEnergy’s decommissioning funding obligations are expected to increase. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning of these nuclear facilities.
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On August 27, 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. On December 27 and 28, 2010, a group of petitioners filed a request for hearing contending that FENOC failed to adequately consider wind or solar generation, or some combination thereof, as an alternative to license extension at Davis-Besse. They further argued FENOC had failed to adequately assess the cost of a severe accident at Davis-Besse. FENOC and the NRC staff responded to this pleading on January 21, 2011, demonstrating that none of the petitioners’ arguments were admissible contentions under the National Environmental Policy Act or NRC regulations. An Atomic Safety and Licensing Board panel is expected to determine whether a hearing is necessary.
Ohio Legal Matters
On February 16, 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. On March 18, 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.
15. SEGMENT INFORMATION
Financial information for each of FirstEnergy’s reportable segments is presented in the following table. FES and the Utilities do not have separate reportable operating segments.
The Energy Delivery Services segment transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey, and purchases power for its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Ohio, Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES and from non-affiliated power suppliers, the net PJM and MISO transmission expenses related to the delivery of the respective generation loads and the deferral and amortization of purchased power costs.
The Competitive Energy Services segment supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. This business segment controls approximately 13,236 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
The other segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
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Segment Financial Information
| Energy | Competitive | |||||||||||||||||||
| For the Years Ended | Delivery | Energy | Reconciling | |||||||||||||||||
| December 31, | Services | Services | Other | Adjustments | Consolidated | |||||||||||||||
| (In millions) | ||||||||||||||||||||
2010 | ||||||||||||||||||||
| External revenues | $ | 9,813 | $ | 3,544 | $ | 33 | $ | (125 | ) | $ | 13,265 | |||||||||
| Internal revenues* | 139 | 2,301 | — | (2,366 | ) | 74 | ||||||||||||||
| 9,952 | 5,845 | 33 | (2,491 | ) | 13,339 | |||||||||||||||
| Depreciation and amortization | 1,173 | 254 | 32 | 9 | 1,468 | |||||||||||||||
| Investment income | 102 | 51 | 1 | (37 | ) | 117 | ||||||||||||||
| Net interest charges | 491 | 129 | 6 | 54 | 680 | |||||||||||||||
| Income taxes | 372 | 158 | (13 | ) | (35 | ) | 482 | |||||||||||||
| Net income | 607 | 258 | (4 | ) | (101 | ) | 760 | |||||||||||||
| Total assets | 22,613 | 11,240 | 618 | 334 | 34,805 | |||||||||||||||
| Total goodwill | 5,551 | 24 | — | — | 5,575 | |||||||||||||||
| Property additions | 745 | 1,129 | 24 | 65 | 1,963 | |||||||||||||||
2009 | ||||||||||||||||||||
| External revenues | $ | 11,144 | $ | 1,894 | $ | 37 | $ | (119 | ) | $ | 12,956 | |||||||||
| Internal revenues* | — | 2,843 | — | (2,826 | ) | 17 | ||||||||||||||
| 11,144 | 4,737 | 37 | (2,945 | ) | 12,973 | |||||||||||||||
| Depreciation and amortization | 1,464 | 270 | 10 | 11 | 1,755 | |||||||||||||||
| Investment income | 139 | 121 | — | (56 | ) | 204 | ||||||||||||||
| Net interest charges | 469 | 106 | 8 | 265 | 848 | |||||||||||||||
| Income taxes | 290 | 345 | (265 | ) | (125 | ) | 245 | |||||||||||||
| Net income | 435 | 517 | 257 | (219 | ) | 990 | ||||||||||||||
| Total assets | 22,978 | 10,584 | 607 | 135 | 34,304 | |||||||||||||||
| Total goodwill | 5,551 | 24 | — | — | 5,575 | |||||||||||||||
| Property additions | 750 | 1,262 | 149 | 42 | 2,203 | |||||||||||||||
2008 | ||||||||||||||||||||
| External revenues | $ | 12,068 | $ | 1,571 | $ | 72 | $ | (84 | ) | $ | 13,627 | |||||||||
| Internal revenues | — | 2,968 | — | (2,968 | ) | — | ||||||||||||||
| 12,068 | 4,539 | 72 | (3,052 | ) | 13,627 | |||||||||||||||
| Depreciation and amortization | 1,154 | 243 | 4 | 13 | 1,414 | |||||||||||||||
| Investment income | 171 | (34 | ) | 6 | (84 | ) | 59 | |||||||||||||
| Net interest charges | 408 | 108 | 2 | 184 | 702 | |||||||||||||||
| Income taxes | 611 | 314 | (53 | ) | (95 | ) | 777 | |||||||||||||
| Net income | 916 | 472 | 116 | (165 | ) | 1,339 | ||||||||||||||
| Total assets | 23,025 | 9,559 | 539 | 398 | 33,521 | |||||||||||||||
| Total goodwill | 5,551 | 24 | — | — | 5,575 | |||||||||||||||
| Property additions | 839 | 1,835 | 176 | 38 | 2,888 | |||||||||||||||
| * | Under the accounting standard for the effects of certain types of regulation, internal revenues are not fully offset for sales of RECs by FES to the Ohio Companies that are retained in inventory. |
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
Products and Services
| Electricity | ||||
| Year | Sales | |||
| (in millions) | ||||
| 2010 | $ | 12,523 | ||
| 2009 | 12,032 | |||
| 2008 | 12,693 | |||
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16. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010, the FASB Emerging Issues Task Force amended the Goodwill and Other Topic of the FASB Accounting Standards Codification. The amendment requires entities with a zero or negative carrying value to assess whether it is more likely than not that a goodwill impairment exists through the consideration of qualitative factors. If an entity concludes that it is more likely than not that a goodwill impairment exists, the entity must perform step 2 of the goodwill impairment test. The amendment is effective for fiscal years, and interim periods within those years, beginning after December 15, 2010. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
In 2010, the FASB Emerging Issues Task Force amended the Business Combinations Topic of the FASB Accounting Standards Codification. The amendment addresses how entities prepare pro forma financial information as a result of a business combination. Under the amendment, if comparative financial statements are presented an entity should present the pro forma disclosures as if the business combination occurred at the beginning of the prior annual period. An entity must provide additional disclosures describing the nature and amount of material, nonrecurring pro forma adjustments. The amendment is effective for business combinations consummated in periods beginning after December 15, 2010. FirstEnergy will implement the amendment to Business Combinations guidance for acquisitions consummated after January 1, 2011.
17. TRANSACTIONS WITH AFFILIATED COMPANIES
FES’ and the Utilities’ operating revenues, operating expenses, investment income and interest expense include transactions with affiliated companies. These affiliated company transactions include PSAs between FES and the Utilities, support service billings from FESC and FENOC, interest on associated company notes and other transactions (see Note 7).
The Ohio Companies had a full requirements PSA with FES through December 31, 2008 to meet their POLR and default service obligations. Met-Ed and Penelec had a partial requirement PSA with FES to meet a portion of their POLR and default service obligations through the end of 2010 (see Note 9). FES is incurring interest expense through FGCO and NGC on associated company notes payable to the Ohio Companies and Penn related to the 2005 intra-system generation asset transfers. The primary affiliated company transactions for FES and the Utilities during the three years ended December 31, 2010 are as follows:
| Affiliated Company Transactions — 2010 | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
| Electric sales to affiliates | $ | 2,227 | $ | 190 | $ | 2 | $ | 46 | $ | — | $ | 73 | $ | 65 | ||||||||||||||
| Ground lease with ATSI | — | 12 | 7 | 2 | — | — | — | |||||||||||||||||||||
| Other | 88 | 1 | 7 | 1 | — | 10 | — | |||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||
| Purchased power from affiliates | 371 | 521 | 361 | 181 | — | 612 | 643 | |||||||||||||||||||||
| Fuel | 46 | — | — | — | — | — | — | |||||||||||||||||||||
| Support services | 620 | 128 | 64 | 52 | 94 | 59 | 58 | |||||||||||||||||||||
Investment Income: | ||||||||||||||||||||||||||||
| Interest income from affiliates | — | — | — | 12 | — | — | — | |||||||||||||||||||||
| Interest income from FirstEnergy | 3 | — | — | — | — | — | — | |||||||||||||||||||||
Interest Expense: | ||||||||||||||||||||||||||||
| Interest expense to affiliates | 9 | 3 | 14 | 1 | 4 | 2 | 2 | |||||||||||||||||||||
| Interest expense to FirstEnergy | — | — | 1 | — | — | — | — | |||||||||||||||||||||
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| Affiliated Company Transactions — 2009 | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
| Electric sales to affiliates | $ | 2,826 | $ | 189 | $ | 2 | $ | 38 | $ | — | $ | — | $ | — | ||||||||||||||
| Ground lease with ATSI | — | 12 | 7 | 2 | — | — | — | |||||||||||||||||||||
| Other | 30 | 1 | 6 | 1 | — | 10 | — | |||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||
| Purchased power from affiliates | 222 | 991 | 735 | 393 | — | 365 | 342 | |||||||||||||||||||||
| Fuel | 15 | — | — | — | — | — | — | |||||||||||||||||||||
| Support services | 584 | 141 | 62 | 59 | 91 | 54 | 57 | |||||||||||||||||||||
Investment Income: | ||||||||||||||||||||||||||||
| Interest income from affiliates | — | 15 | — | 17 | — | — | — | |||||||||||||||||||||
| Interest income from FirstEnergy | 4 | 1 | — | — | — | 1 | — | |||||||||||||||||||||
Interest Expense: | ||||||||||||||||||||||||||||
| Interest expense to affiliates | 6 | 5 | 17 | 2 | 4 | 3 | 2 | |||||||||||||||||||||
| Interest expense to FirstEnergy | 4 | 1 | 1 | 1 | — | — | 1 | |||||||||||||||||||||
| Affiliated Company Transactions — 2008 | FES | OE | CEI | TE | JCP&L | Met-Ed | Penelec | |||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||
Revenues: | ||||||||||||||||||||||||||||
| Electric sales to affiliates | $ | 2,968 | $ | 75 | $ | 6 | $ | 32 | $ | — | $ | — | $ | — | ||||||||||||||
| Ground lease with ATSI | — | 12 | 7 | 2 | — | — | — | |||||||||||||||||||||
| Other | 6 | 1 | 12 | 3 | 1 | 10 | 1 | |||||||||||||||||||||
Expenses: | ||||||||||||||||||||||||||||
| Purchased power from affiliates | 101 | 1,203 | 766 | 411 | — | 304 | 284 | |||||||||||||||||||||
| Fuel | 5 | — | — | — | — | — | — | |||||||||||||||||||||
| Support services | 584 | 146 | 69 | 71 | 95 | 57 | 59 | |||||||||||||||||||||
Investment Income: | ||||||||||||||||||||||||||||
| Interest income from affiliates | 1 | 15 | 1 | 20 | 1 | — | 1 | |||||||||||||||||||||
| Interest income from FirstEnergy | 12 | 13 | — | — | — | — | — | |||||||||||||||||||||
Interest Expense: | ||||||||||||||||||||||||||||
| Interest expense to affiliates | 4 | 3 | 19 | 1 | 3 | 2 | 2 | |||||||||||||||||||||
| Interest expense to FirstEnergy | 26 | — | 7 | 2 | 5 | 4 | 5 | |||||||||||||||||||||
FirstEnergy does not bill directly or allocate any of its costs to any subsidiary company. Costs are allocated to FES and the Utilities from FESC and FENOC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC and FENOC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Management believes that these allocation methods are reasonable. Intercompany transactions with FirstEnergy and its other subsidiaries are generally settled under commercial terms within thirty days.
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18. SUPPLEMENTAL GUARANTOR INFORMATION
As discussed in Note 7, FES has fully and unconditionally guaranteed all of FGCO’s obligations under each of the leases associated with Bruce Mansfield Unit 1. The Consolidating Statements of Income for the three years ended December 31, 2010, Consolidating Balance Sheets as of December 31, 2010, and December 31, 2009, and Condensed Consolidating Statements of Cash Flows for the three years ended December 31, 2010, for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved (see Note 7). The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
| For the Year Ended December 31, 2010 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
REVENUES | $ | 5,665,077 | $ | 2,435,027 | $ | 1,567,728 | $ | (3,840,218 | ) | $ | 5,827,614 | |||||||||
EXPENSES: | ||||||||||||||||||||
| Fuel | 30,618 | 1,200,432 | 171,789 | — | 1,402,839 | |||||||||||||||
| Purchased power from affiliates | 3,948,399 | 30,496 | 232,015 | (3,840,218 | ) | 370,692 | ||||||||||||||
| Purchased power from non-affiliates | 1,585,207 | — | — | — | 1,585,207 | |||||||||||||||
| Other operating expenses | 315,767 | 377,534 | 537,281 | 48,758 | 1,279,340 | |||||||||||||||
| Provision for depreciation | 3,083 | 99,386 | 146,051 | (5,224 | ) | 243,296 | ||||||||||||||
| General taxes | 23,869 | 42,337 | 27,571 | — | 93,777 | |||||||||||||||
| Impairment of long-lived assets | — | 383,665 | — | — | 383,665 | |||||||||||||||
| Total expenses | 5,906,943 | 2,133,850 | 1,114,707 | (3,796,684 | ) | 5,358,816 | ||||||||||||||
OPERATING INCOME (LOSS) | (241,866 | ) | 301,177 | 453,021 | (43,534 | ) | 468,798 | |||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
| Investment income | 4,679 | 908 | 53,615 | — | 59,202 | |||||||||||||||
| Miscellaneous income, including net income from equity investees | 485,467 | 647 | 56 | (469,503 | ) | 16,667 | ||||||||||||||
| Interest expense — affiliates | (240 | ) | (7,830 | ) | (1,685 | ) | — | (9,755 | ) | |||||||||||
| Interest expense — other | (95,825 | ) | (108,543 | ) | (65,385 | ) | 63,653 | (206,100 | ) | |||||||||||
| Capitalized interest | 399 | 74,655 | 16,619 | — | 91,673 | |||||||||||||||
| Total other income (expense) | 394,480 | (40,163 | ) | 3,220 | (405,850 | ) | (48,313 | ) | ||||||||||||
INCOME BEFORE INCOME TAXES | 152,614 | 261,014 | 456,241 | (449,384 | ) | 420,485 | ||||||||||||||
INCOME TAXES (BENEFITS) | (116,814 | ) | 81,621 | 167,435 | 18,815 | 151,057 | ||||||||||||||
NET INCOME | $ | 269,428 | $ | 179,393 | $ | 288,806 | $ | (468,199 | ) | $ | 269,428 | |||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
| For the Year Ended December 31, 2009 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
REVENUES | $ | 4,390,111 | $ | 2,216,237 | $ | 1,360,522 | $ | (3,238,533 | ) | $ | 4,728,337 | |||||||||
EXPENSES: | ||||||||||||||||||||
| Fuel | 18,416 | 971,021 | 138,026 | — | 1,127,463 | |||||||||||||||
| Purchased power from affiliates | 3,220,197 | 18,336 | 222,406 | (3,238,533 | ) | 222,406 | ||||||||||||||
| Purchased power from non-affiliates | 996,383 | — | — | — | 996,383 | |||||||||||||||
| Other operating expenses | 220,660 | 395,330 | 518,473 | 48,762 | 1,183,225 | |||||||||||||||
| Provision for depreciation | 4,147 | 121,007 | 139,488 | (5,249 | ) | 259,393 | ||||||||||||||
| General taxes | 18,214 | 44,075 | 24,626 | — | 86,915 | |||||||||||||||
| Impairment of long-lived assets | — | 6,067 | — | — | 6,067 | |||||||||||||||
| Total expenses | 4,478,017 | 1,555,836 | 1,043,019 | (3,195,020 | ) | 3,881,852 | ||||||||||||||
OPERATING INCOME (LOSS) | (87,906 | ) | 660,401 | 317,503 | (43,513 | ) | 846,485 | |||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
| Investment income | 5,297 | 683 | 119,246 | — | 125,226 | |||||||||||||||
| Miscellaneous income (expense), including net income from equity investees | 656,451 | 2,136 | 61 | (645,911 | ) | 12,737 | ||||||||||||||
| Interest expense — affiliates | (135 | ) | (5,619 | ) | (4,352 | ) | — | (10,106 | ) | |||||||||||
| Interest expense — other | (44,837 | ) | (99,802 | ) | (62,034 | ) | 64,553 | (142,120 | ) | |||||||||||
| Capitalized interest | 212 | 49,577 | 10,363 | — | 60,152 | |||||||||||||||
| Total other income (expense) | 616,988 | (53,025 | ) | 63,284 | (581,358 | ) | 45,889 | |||||||||||||
INCOME BEFORE INCOME TAXES | 529,082 | 607,376 | 380,787 | (624,871 | ) | 892,374 | ||||||||||||||
INCOME TAXES (BENEFITS) | (48,002 | ) | 207,171 | 135,785 | 20,336 | 315,290 | ||||||||||||||
NET INCOME | $ | 577,084 | $ | 400,205 | $ | 245,002 | $ | (645,207 | ) | $ | 577,084 | |||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING STATEMENTS OF INCOME
| For the Year Ended December 31, 2008 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
REVENUES | $ | 4,470,112 | $ | 2,275,451 | $ | 1,204,534 | $ | (3,431,744 | ) | $ | 4,518,353 | |||||||||
EXPENSES: | ||||||||||||||||||||
| Fuel | 16,322 | 1,171,993 | 126,978 | — | 1,315,293 | |||||||||||||||
| Purchased power from affiliates | 3,417,126 | 14,618 | 101,409 | (3,431,744 | ) | 101,409 | ||||||||||||||
| Purchased power from non-affiliates | 778,882 | — | — | — | 778,882 | |||||||||||||||
| Other operating expenses | 116,972 | 416,723 | 502,096 | 48,757 | 1,084,548 | |||||||||||||||
| Provision for depreciation | 5,986 | 119,763 | 111,529 | (5,379 | ) | 231,899 | ||||||||||||||
| General taxes | 19,260 | 46,153 | 22,591 | — | 88,004 | |||||||||||||||
| Total expenses | 4,354,548 | 1,769,250 | 864,603 | (3,388,366 | ) | 3,600,035 | ||||||||||||||
OPERATING INCOME | 115,564 | 506,201 | 339,931 | (43,378 | ) | 918,318 | ||||||||||||||
OTHER INCOME (EXPENSE): | ||||||||||||||||||||
| Investment income | 10,953 | 2,034 | (35,665 | ) | — | (22,678 | ) | |||||||||||||
| Miscellaneous income (expense), including net income from equity investees | 438,214 | (5,400 | ) | — | (431,116 | ) | 1,698 | |||||||||||||
| Interest expense to affiliates | (314 | ) | (20,342 | ) | (9,173 | ) | — | (29,829 | ) | |||||||||||
| Interest expense — other | (24,674 | ) | (95,926 | ) | (56,486 | ) | 65,404 | (111,682 | ) | |||||||||||
| Capitalized interest | 142 | 39,934 | 3,688 | — | 43,764 | |||||||||||||||
| Total other income (expense) | 424,321 | (79,700 | ) | (97,636 | ) | (365,712 | ) | (118,727 | ) | |||||||||||
INCOME BEFORE INCOME TAXES | 539,885 | 426,501 | 242,295 | (409,090 | ) | 799,591 | ||||||||||||||
INCOME TAXES | 33,475 | 155,100 | 90,247 | 14,359 | 293,181 | |||||||||||||||
NET INCOME | $ | 506,410 | $ | 271,401 | $ | 152,048 | $ | (423,449 | ) | $ | 506,410 | |||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
| As of December 31, 2010 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
CURRENT ASSETS: | ||||||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 9,273 | $ | 8 | $ | — | $ | 9,281 | ||||||||||
| Receivables- | ||||||||||||||||||||
| Customers | 365,758 | — | — | — | 365,758 | |||||||||||||||
| Associated companies | 333,323 | 356,564 | 125,716 | (338,038 | ) | 477,565 | ||||||||||||||
| Other | 21,010 | 55,758 | 12,782 | — | 89,550 | |||||||||||||||
| Notes receivable from associated companies | 34,331 | 188,796 | 173,643 | — | 396,770 | |||||||||||||||
| Materials and supplies, at average cost | 40,713 | 276,149 | 228,480 | — | 545,342 | |||||||||||||||
| Derivatives | 181,660 | — | — | — | 181,660 | |||||||||||||||
| Prepayments and other | 47,712 | 11,352 | 1,107 | — | 60,171 | |||||||||||||||
| 1,024,507 | 897,892 | 541,736 | (338,038 | ) | 2,126,097 | |||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | ||||||||||||||||||||
| In service | 96,371 | 6,197,776 | 5,411,852 | (384,681 | ) | 11,321,318 | ||||||||||||||
| Less — Accumulated provision for depreciation | 17,039 | 2,020,463 | 2,162,173 | (175,395 | ) | 4,024,280 | ||||||||||||||
| 79,332 | 4,177,313 | 3,249,679 | (209,286 | ) | 7,297,038 | |||||||||||||||
| Construction work in progress | 8,809 | 519,651 | 534,284 | — | 1,062,744 | |||||||||||||||
| 88,141 | 4,696,964 | 3,783,963 | (209,286 | ) | 8,359,782 | |||||||||||||||
INVESTMENTS: | ||||||||||||||||||||
| Nuclear plant decommissioning trusts | — | — | 1,145,846 | — | 1,145,846 | |||||||||||||||
| Investment in associated companies | 4,941,763 | — | — | (4,941,763 | ) | — | ||||||||||||||
| Other | 374 | 11,128 | 202 | — | 11,704 | |||||||||||||||
| 4,942,137 | 11,128 | 1,146,048 | (4,941,763 | ) | 1,157,550 | |||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||||||||||||||
| Accumulated deferred income tax benefits | 42,986 | 412,427 | — | (455,413 | ) | — | ||||||||||||||
| Customer intangibles | 133,968 | — | — | — | 133,968 | |||||||||||||||
| Goodwill | 24,248 | — | — | — | 24,248 | |||||||||||||||
| Property taxes | — | 16,463 | 24,649 | — | 41,112 | |||||||||||||||
| Unamortized sale and leaseback costs | — | 10,828 | — | 62,558 | 73,386 | |||||||||||||||
| Derivatives | 97,603 | — | — | — | 97,603 | |||||||||||||||
| Other | 21,018 | 70,810 | 14,463 | (57,602 | ) | 48,689 | ||||||||||||||
| 319,823 | 510,528 | 39,112 | (450,457 | ) | 419,006 | |||||||||||||||
| $ | 6,374,608 | $ | 6,116,512 | $ | 5,510,859 | $ | (5,939,544 | ) | $ | 12,062,435 | ||||||||||
LIABILITIES AND CAPITALIZATION | ||||||||||||||||||||
CURRENT LIABILITIES: | ||||||||||||||||||||
| Currently payable long-term debt | $ | 100,775 | $ | 418,832 | $ | 632,106 | $ | (19,578 | ) | $ | 1,132,135 | |||||||||
| Short-term borrowings- | ||||||||||||||||||||
| Associated companies | — | 11,561 | — | — | 11,561 | |||||||||||||||
| Accounts payable- | ||||||||||||||||||||
| Associated companies | 351,172 | 212,620 | 249,820 | (346,989 | ) | 466,623 | ||||||||||||||
| Other | 139,037 | 102,154 | — | — | 241,191 | |||||||||||||||
| Accrued taxes | 3,358 | 36,187 | 30,726 | (142 | ) | 70,129 | ||||||||||||||
| Derivatives | 266,411 | — | — | — | 266,411 | |||||||||||||||
| Other | 51,619 | 147,754 | 15,156 | 37,142 | 251,671 | |||||||||||||||
| 912,372 | 929,108 | 927,808 | (329,567 | ) | 2,439,721 | |||||||||||||||
CAPITALIZATION: | ||||||||||||||||||||
| Total equity | 3,788,245 | 2,514,775 | 2,413,580 | (4,928,859 | ) | 3,787,741 | ||||||||||||||
| Long-term debt and other long-term obligations | 1,518,586 | 2,118,791 | 793,250 | (1,249,752 | ) | 3,180,875 | ||||||||||||||
| 5,306,831 | 4,633,566 | 3,206,830 | (6,178,611 | ) | 6,968,616 | |||||||||||||||
NONCURRENT LIABILITIES: | ||||||||||||||||||||
| Deferred gain on sale and leaseback transaction | — | — | — | 959,154 | 959,154 | |||||||||||||||
| Accumulated deferred income taxes | — | — | 448,115 | (390,520 | ) | 57,595 | ||||||||||||||
| Accumulated deferred investment tax credits | — | 33,280 | 20,944 | — | 54,224 | |||||||||||||||
| Asset retirement obligations | — | 26,780 | 865,271 | — | 892,051 | |||||||||||||||
| Retirement benefits | 48,214 | 236,946 | — | — | 285,160 | |||||||||||||||
| Property taxes | — | 16,463 | 24,649 | — | 41,112 | |||||||||||||||
| Lease market valuation liability | — | 216,695 | — | — | 216,695 | |||||||||||||||
| Other | 107,191 | 23,674 | 17,242 | — | 148,107 | |||||||||||||||
| 155,405 | 553,838 | 1,376,221 | 568,634 | 2,654,098 | ||||||||||||||||
| $ | 6,374,608 | $ | 6,116,512 | $ | 5,510,859 | $ | (5,939,544 | ) | $ | 12,062,435 | ||||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATING BALANCE SHEETS
| As of December 31, 2009 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
ASSETS | ||||||||||||||||||||
CURRENT ASSETS: | ||||||||||||||||||||
| Cash and cash equivalents | $ | — | $ | 3 | $ | 9 | $ | — | $ | 12 | ||||||||||
| Receivables- | ||||||||||||||||||||
| Customers | 195,107 | — | — | — | 195,107 | |||||||||||||||
| Associated companies | 305,298 | 175,730 | 134,841 | (297,308 | ) | 318,561 | ||||||||||||||
| Other | 28,394 | 10,960 | 12,518 | — | 51,872 | |||||||||||||||
| Notes receivable from associated companies | 416,404 | 240,836 | 147,863 | — | 805,103 | |||||||||||||||
| Materials and supplies, at average cost | 17,265 | 307,079 | 215,197 | — | 539,541 | |||||||||||||||
| Derivatives | 31,485 | — | — | — | 31,485 | |||||||||||||||
| Prepayments and other | 48,540 | 18,356 | 9,401 | — | 76,297 | |||||||||||||||
| 1,042,493 | 752,964 | 519,829 | (297,308 | ) | 2,017,978 | |||||||||||||||
PROPERTY, PLANT AND EQUIPMENT: | ||||||||||||||||||||
| In service | 90,474 | 5,478,346 | 5,174,835 | (386,023 | ) | 10,357,632 | ||||||||||||||
| Less — Accumulated provision for depreciation | 13,649 | 2,778,320 | 1,910,701 | (171,512 | ) | 4,531,158 | ||||||||||||||
| 76,825 | 2,700,026 | 3,264,134 | (214,511 | ) | 5,826,474 | |||||||||||||||
| Construction work in progress | 6,032 | 2,049,078 | 368,336 | — | 2,423,446 | |||||||||||||||
| 82,857 | 4,749,104 | 3,632,470 | (214,511 | ) | 8,249,920 | |||||||||||||||
INVESTMENTS: | ||||||||||||||||||||
| Nuclear plant decommissioning trusts | — | — | 1,088,641 | — | 1,088,641 | |||||||||||||||
| Investment in associated companies | 4,477,602 | — | — | (4,477,602 | ) | — | ||||||||||||||
| Other | 1,137 | 21,127 | 202 | — | 22,466 | |||||||||||||||
| 4,478,739 | 21,127 | 1,088,843 | (4,477,602 | ) | 1,111,107 | |||||||||||||||
DEFERRED CHARGES AND OTHER ASSETS: | ||||||||||||||||||||
| Accumulated deferred income taxes | 93,379 | 381,849 | — | (388,602 | ) | 86,626 | ||||||||||||||
| Customer intangibles | 16,566 | — | — | — | 16,566 | |||||||||||||||
| Goodwill | 24,248 | — | — | — | 24,248 | |||||||||||||||
| Property taxes | — | 27,811 | 22,314 | — | 50,125 | |||||||||||||||
| Unamortized sale and leaseback costs | — | 16,454 | — | 56,099 | 72,553 | |||||||||||||||
| Derivatives | 28,368 | — | — | — | 28,368 | |||||||||||||||
| Other | 54,477 | 71,179 | 18,755 | (51,114 | ) | 93,297 | ||||||||||||||
| 217,038 | 497,293 | 41,069 | (383,617 | ) | 371,783 | |||||||||||||||
| $ | 5,821,127 | $ | 6,020,488 | $ | 5,282,211 | $ | (5,373,038 | ) | $ | 11,750,788 | ||||||||||
LIABILITIES AND CAPITALIZATION | ||||||||||||||||||||
CURRENT LIABILITIES: | ||||||||||||||||||||
| Currently payable long-term debt | $ | 736 | $ | 646,402 | $ | 922,429 | $ | (18,640 | ) | $ | 1,550,927 | |||||||||
| Short-term borrowings- | ||||||||||||||||||||
| Associated companies | — | 9,237 | — | — | 9,237 | |||||||||||||||
| Accounts payable- | ||||||||||||||||||||
| Associated companies | 261,788 | 170,446 | 295,045 | (261,201 | ) | 466,078 | ||||||||||||||
| Other | 51,722 | 193,641 | — | — | 245,363 | |||||||||||||||
| Accrued taxes | 44,213 | 61,055 | 22,777 | (44,887 | ) | 83,158 | ||||||||||||||
| Derivatives | 125,609 | — | — | — | 125,609 | |||||||||||||||
| Other | 47,406 | 132,314 | 16,734 | 36,994 | 233,448 | |||||||||||||||
| 531,474 | 1,213,095 | 1,256,985 | (287,734 | ) | 2,713,820 | |||||||||||||||
CAPITALIZATION: | ||||||||||||||||||||
| Common stockholder’s equity | 3,514,571 | 2,346,515 | 2,119,488 | (4,466,003 | ) | 3,514,571 | ||||||||||||||
| Long-term debt and other long-term obligations | 1,619,339 | 1,906,818 | 554,825 | (1,269,330 | ) | 2,811,652 | ||||||||||||||
| 5,133,910 | 4,253,333 | 2,674,313 | (5,735,333 | ) | 6,326,223 | |||||||||||||||
NONCURRENT LIABILITIES: | ||||||||||||||||||||
| Deferred gain on sale and leaseback transaction | — | — | — | 992,869 | 992,869 | |||||||||||||||
| Accumulated deferred income taxes | — | — | 342,840 | (342,840 | ) | — | ||||||||||||||
| Accumulated deferred investment tax credits | — | 36,359 | 22,037 | — | 58,396 | |||||||||||||||
| Asset retirement obligations | — | 25,714 | 895,734 | — | 921,448 | |||||||||||||||
| Retirement benefits | 33,144 | 170,891 | — | — | 204,035 | |||||||||||||||
| Property taxes | — | 27,811 | 22,314 | — | 50,125 | |||||||||||||||
| Lease market valuation liability | — | 262,200 | — | — | 262,200 | |||||||||||||||
| Other | 122,599 | 31,085 | 67,988 | — | 221,672 | |||||||||||||||
| 155,743 | 554,060 | 1,350,913 | 650,029 | 2,710,745 | ||||||||||||||||
| $ | 5,821,127 | $ | 6,020,488 | $ | 5,282,211 | $ | (5,373,038 | ) | $ | 11,750,788 | ||||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
| For the Year Ended December 31, 2010 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (259,812 | ) | $ | 379,829 | $ | 684,745 | $ | (18,640 | ) | $ | 786,122 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
| New Financing- | ||||||||||||||||||||
| Long-term debt | — | 318,520 | 396,850 | — | 715,370 | |||||||||||||||
| Short-term borrowings, net | — | 2,324 | — | — | 2,324 | |||||||||||||||
| Redemptions and Repayments- | ||||||||||||||||||||
| Long-term debt | (804 | ) | (341,542 | ) | (448,748 | ) | 18,640 | (772,454 | ) | |||||||||||
| Other | (460 | ) | (750 | ) | (930 | ) | — | (2,140 | ) | |||||||||||
| Net cash used for financing activities | (1,264 | ) | (21,448 | ) | (52,828 | ) | 18,640 | (56,900 | ) | |||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
| Property additions | (8,367 | ) | (518,731 | ) | (507,587 | ) | — | (1,034,685 | ) | |||||||||||
| Proceeds from asset sales | — | 117,333 | — | — | 117,333 | |||||||||||||||
| Sales of investment securities held in trusts | — | — | 1,926,684 | — | 1,926,684 | |||||||||||||||
| Purchases of investment securities held in trusts | — | — | (1,974,020 | ) | — | (1,974,020 | ) | |||||||||||||
| Loans from (to) associated companies, net | 382,073 | 52,040 | (25,780 | ) | — | 408,333 | ||||||||||||||
| Customer acquisition costs | (113,336 | ) | — | — | — | (113,336 | ) | |||||||||||||
| Leasehold improvement payments to associated companies | — | — | (51,204 | ) | — | (51,204 | ) | |||||||||||||
| Other | 706 | 247 | (11 | ) | — | 942 | ||||||||||||||
| Net cash provided from (used for) investing activities | 261,076 | (349,111 | ) | (631,918 | ) | — | (719,953 | ) | ||||||||||||
| Net change in cash and cash equivalents | — | 9,270 | (1 | ) | — | 9,269 | ||||||||||||||
| Cash and cash equivalents at beginning of period | — | 3 | 9 | — | 12 | |||||||||||||||
| Cash and cash equivalents at end of period | $ | — | $ | 9,273 | $ | 8 | $ | — | $ | 9,281 | ||||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
| For the Year Ended December 31, 2009 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | $ | (20,027 | ) | $ | 790,411 | $ | 621,649 | $ | (17,744 | ) | $ | 1,374,289 | ||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
| New Financing- | ||||||||||||||||||||
| Long-term debt | 1,498,087 | 576,800 | 363,515 | — | 2,438,402 | |||||||||||||||
| Equity contributions from parent | — | 100,000 | 150,000 | (250,000 | ) | — | ||||||||||||||
| Redemptions and Repayments- | ||||||||||||||||||||
| Long-term debt | (1,766 | ) | (320,754 | ) | (404,383 | ) | 17,747 | (709,156 | ) | |||||||||||
| Short-term borrowings, net | (901,119 | ) | (248,120 | ) | (6,347 | ) | — | (1,155,586 | ) | |||||||||||
| Other | (12,054 | ) | (6,157 | ) | (3,576 | ) | (3 | ) | (21,790 | ) | ||||||||||
| Net cash provided from financing activities | 583,148 | 101,769 | 99,209 | (232,256 | ) | 551,870 | ||||||||||||||
| �� | ||||||||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
| Property additions | (4,372 | ) | (671,691 | ) | (546,869 | ) | — | (1,222,932 | ) | |||||||||||
| Proceeds from asset sales | — | 18,371 | — | — | 18,371 | |||||||||||||||
| Sales of investment securities held in trusts | — | — | 1,379,154 | — | 1,379,154 | |||||||||||||||
| Purchases of investment securities held in trusts | — | — | (1,405,996 | ) | — | (1,405,996 | ) | |||||||||||||
| Loans to associated companies, net | (309,175 | ) | (218,890 | ) | (147,863 | ) | — | (675,928 | ) | |||||||||||
| Investment in subsidiary | (250,000 | ) | — | — | 250,000 | — | ||||||||||||||
| Other | 426 | (20,006 | ) | 725 | — | (18,855 | ) | |||||||||||||
| Net cash used for investing activities | (563,121 | ) | (892,216 | ) | (720,849 | ) | 250,000 | (1,926,186 | ) | |||||||||||
| Net change in cash and cash equivalents | — | (36 | ) | 9 | — | (27 | ) | |||||||||||||
| Cash and cash equivalents at beginning of period | — | 39 | — | — | 39 | |||||||||||||||
| Cash and cash equivalents at end of period | $ | — | $ | 3 | $ | 9 | $ | — | $ | 12 | ||||||||||
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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
| For the Year Ended December 31, 2008 | FES | FGCO | NGC | Eliminations | Consolidated | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
NET CASH PROVIDED FROM OPERATING ACTIVITIES | $ | 40,791 | $ | 350,986 | $ | 478,047 | $ | (16,896 | ) | $ | 852,928 | |||||||||
CASH FLOWS FROM FINANCING ACTIVITIES: | ||||||||||||||||||||
| New Financing- | ||||||||||||||||||||
| Long-term debt | — | 353,325 | 265,050 | — | 618,375 | |||||||||||||||
| Equity contributions from parent | 280,000 | 675,000 | 175,000 | (850,000 | ) | 280,000 | ||||||||||||||
| Short-term borrowings, net | 701,119 | 18,571 | — | (18,931 | ) | 700,759 | ||||||||||||||
| Redemptions and Repayments- | ||||||||||||||||||||
| Long-term debt | (2,955 | ) | (293,349 | ) | (183,132 | ) | 16,896 | (462,540 | ) | |||||||||||
| Short-term borrowings, net | — | — | (18,931 | ) | 18,931 | — | ||||||||||||||
| Common stock dividend payment | (43,000 | ) | — | — | — | (43,000 | ) | |||||||||||||
| Other | — | (3,107 | ) | (2,040 | ) | — | (5,147 | ) | ||||||||||||
| Net cash provided from financing activities | 935,164 | 750,440 | 235,947 | (833,104 | ) | 1,088,447 | ||||||||||||||
CASH FLOWS FROM INVESTING ACTIVITIES: | ||||||||||||||||||||
| Property additions | (43,244 | ) | (1,047,917 | ) | (744,468 | ) | — | (1,835,629 | ) | |||||||||||
| Proceeds from asset sales | — | 23,077 | — | — | 23,077 | |||||||||||||||
| Sales of investment securities held in trusts | — | — | 950,688 | — | 950,688 | |||||||||||||||
| Purchases of investment securities held in trusts | — | — | (987,304 | ) | — | (987,304 | ) | |||||||||||||
| Loans to associated companies, net | (83,457 | ) | (21,946 | ) | 69,012 | — | (36,391 | ) | ||||||||||||
| Investment in subsidiary | (850,000 | ) | — | — | 850,000 | — | ||||||||||||||
| Other | 744 | (54,601 | ) | (1,922 | ) | — | (55,779 | ) | ||||||||||||
| Net cash used for investing activities | (975,957 | ) | (1,101,387 | ) | (713,994 | ) | 850,000 | (1,941,338 | ) | |||||||||||
| Net change in cash and cash equivalents | (2 | ) | 39 | — | — | 37 | ||||||||||||||
| Cash and cash equivalents at beginning of period | 2 | — | — | — | 2 | |||||||||||||||
| Cash and cash equivalents at end of period | $ | — | $ | 39 | $ | — | $ | — | $ | 39 | ||||||||||
19. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value.
Coal-Fired FGCO Units
On August 12, 2010, FirstEnergy announced its intention to make operational changes at certain coal-fired FGCO units. The announcement of the operational change indicated a need to evaluate the future recoverability of the carrying value of the assets associated with the affected FGCO units. As a result of the recoverability evaluation, FirstEnergy recorded an impairment of $303 million to continuing operations of its competitive energy services segment during the year ended December 31, 2010. This impairment represents a $296 million write down of the carrying value of the assets associated with the affected FGCO units to their estimated fair value and a charge of $7 million for excessive or obsolete inventory identified as a result of the operational changes.
FirstEnergy used various assumptions in evaluating whether the FGCO units’ carrying value was recoverable. The estimated undiscounted cash flows were based on assumptions about budgeted net operating income; the impact of current market conditions on future revenues including a long-term view of future market prices; the impact of reduced customer demand; and the estimated cost of remedial retro-fitting of the FGCO units to comply with proposed changes in federal environmental laws. The result of this evaluation indicated that the carrying costs of the FGCO units were not fully recoverable.
FirstEnergy further evaluated the extent to which the carrying value of the FGCO units exceeded their estimated fair value. FirstEnergy applied the income approach to estimating fair value under a discounted cash flow valuation technique to convert future cash flows expected over the remaining life of the asset group to a single present value. The assumptions used to estimate the non-recurring fair value measurement of the FGCO units applied significant unobservable inputs considered Level 3 under the fair value hierarchy. The estimated cash flows used during the recoverability test were discounted using the weighted average cost of capital for a market participant.
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Mad River
On November 10, 2010, a planned demolition of a 275-foot stack at FGCO’s Mad River Plant resulted in the demolished stack falling in the wrong direction and destroying two generating units at the Mad River plant. The accident resulted in a $5 million write-off of the total carrying value of the assets associated with the destroyed units and a charge of $1 million for fuel oil inventory deemed to be excessive or obsolete as a result of the accident. FirstEnergy recorded an impairment of $6 million to continuing operations of its competitive energy services segment for the year ended December 31, 2010.
R.E. Burger Biomass Units
In 2010 FirstEnergy announced that it was canceling its plan to repower Units 4 and 5 at its R. E. Burger Plant to generate electricity principally with biomass, and instead permanently shut down the units as of December 31, 2010. Since the Burger biomass repowering project was announced, market prices for electricity have fallen significantly and no longer supported a repowered Burger Plant. FirstEnergy’s announcement indicated a need to evaluate the future recoverability of the carrying value of the assets associated with the affected Burger units. As a result of the recoverability evaluation, FirstEnergy recorded an impairment of $72 million to continuing operations of its competitive energy services segment for the year ended December 31, 2010. This impairment represents a $69 million write down of the carrying value of the assets associated with the affected Burger units to their estimated fair value and a charge of $3 million for excessive or obsolete inventory identified as a result of the permanent shut down of the Burger units.
20. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation to customers, and the recorded value is being amortized ratably over the term of the related contracts. Net intangible assets of $134 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of December 31, 2010.
The weighted-average amortization period of these certain customer contract rights as of December 31, 2010, is 9 years. For the year ended December 31, 2010, amortization expense was approximately $9 million. The expected estimated aggregate amortization expense for each of the next five years and for all years thereafter is as follows:
| Future Amortization | ||||
| (In millions) | ||||
| 2011 | $ | 12 | ||
| 2012 | 14 | |||
| 2013 | 16 | |||
| 2014 | 17 | |||
| 2015 | 17 | |||
| Years thereafter | 58 | |||
| Total amortization | $ | 134 | ||
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21. SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)
The following summarizes certain consolidated operating results by quarter for 2010 and 2009.
| Operating | Income (Loss) | Income | Earnings | |||||||||||||||||
| Income | Before | Taxes | Available | |||||||||||||||||
| Three Months Ended | Revenues | (Loss) | Income Taxes | (Benefit) | To FirstEnergy | |||||||||||||||
| (In millions) | ||||||||||||||||||||
FE | ||||||||||||||||||||
| March 31, 2010 | $ | 3,299.0 | $ | 416.0 | $ | 260.0 | $ | 111.0 | $ | 155.0 | ||||||||||
| March 31, 2009 | 3,334.0 | 346.0 | 169.0 | 54.0 | 119.0 | |||||||||||||||
| June 30, 2010 | 3,128.0 | 526.0 | 390.0 | 134.0 | 265.0 | |||||||||||||||
| June 30, 2009 | 3,271.0 | 802.0 | 656.0 | 248.0 | 414.0 | |||||||||||||||
| September 30, 2010 | 3,693.0 | 415.0 | 294.0 | 119.0 | 179.0 | |||||||||||||||
| September 30, 2009 | 3,408.0 | 487.0 | 358.0 | 128.0 | 234.0 | |||||||||||||||
| December 31, 2010 | 3,219.0 | 448.0 | 298.0 | 118.0 | 185.0 | |||||||||||||||
| December 31, 2009 | 2,960.0 | 244.0 | 52.0 | (185.0 | ) | 239.0 | ||||||||||||||
FES | ||||||||||||||||||||
| March 31, 2010 | $ | 1,388.1 | $ | 154.5 | $ | 124.3 | $ | 44.4 | $ | 79.9 | ||||||||||
| March 31, 2009 | 1,226.1 | 304.3 | 262.5 | 91.8 | 170.7 | |||||||||||||||
| June 30, 2010 | 1,314.7 | 215.1 | 202.8 | 68.9 | 133.9 | |||||||||||||||
| June 30, 2009 | 1,341.2 | 468.9 | 466.6 | 169.2 | 297.4 | |||||||||||||||
| September 30, 2010 | 1,553.7 | (47.7 | ) | (42.1 | ) | (5.4 | ) | (36.7 | ) | |||||||||||
| September 30, 2009 | 1,104.6 | 175.7 | 310.8 | 111.2 | 199.7 | |||||||||||||||
| December 31, 2010 | 1,571.1 | 146.9 | 135.5 | 43.2 | 92.3 | |||||||||||||||
| December 31, 2009 | 1,056.4 | (102.4 | ) | (147.5 | ) | (56.9 | ) | (90.7 | ) | |||||||||||
OE | ||||||||||||||||||||
| March 31, 2010 | $ | 508.4 | $ | 72.9 | $ | 55.8 | $ | 19.6 | $ | 36.0 | ||||||||||
| March 31, 2009 | 749.0 | 30.2 | 15.7 | 4.0 | 11.5 | |||||||||||||||
| June 30, 2010 | 439.4 | 63.4 | 49.2 | 11.9 | 37.2 | |||||||||||||||
| June 30, 2009 | 672.2 | 58.8 | 50.5 | 16.9 | 33.5 | |||||||||||||||
| September 30, 2010 | 486.6 | 90.1 | 75.6 | 29.3 | 46.1 | |||||||||||||||
| September 30, 2009 | 602.5 | 52.8 | 50.6 | 15.9 | 34.6 | |||||||||||||||
| December 31, 2010 | 401.7 | 74.0 | 58.6 | 21.2 | 37.4 | |||||||||||||||
December 31, 2009* | 493.2 | 87.1 | 71.8 | 29.4 | 42.3 | |||||||||||||||
CEI | ||||||||||||||||||||
| March 31, 2010 | $ | 330.1 | $ | 50.3 | $ | 24.8 | $ | 10.8 | $ | 13.6 | ||||||||||
| March 31, 2009 | 449.7 | (144.1 | ) | (166.9 | ) | (61.5 | ) | (105.9 | ) | |||||||||||
| June 30, 2010 | 295.7 | 56.7 | 30.7 | 8.8 | 21.6 | |||||||||||||||
| June 30, 2009 | 475.1 | 98.5 | 74.2 | 26.5 | 47.3 | |||||||||||||||
| September 30, 2010 | 328.7 | 64.7 | 38.4 | 13.5 | 24.6 | |||||||||||||||
| September 30, 2009 | 435.5 | 61.6 | 35.1 | 9.8 | 25.0 | |||||||||||||||
| December 31, 2010 | 266.9 | 43.7 | 17.9 | 5.6 | 11.9 | |||||||||||||||
| December 31, 2009 | 315.8 | 64.7 | 36.4 | 15.0 | 20.9 | |||||||||||||||
| * | Includes a $4.8 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods. (See Note 9 for description of adjustment). |
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| Operating | Income (Loss) | Income | Earnings | |||||||||||||||||
| Income | Before | Taxes | Available | |||||||||||||||||
| Three Months Ended | Revenues | (Loss) | Income Taxes | (Benefit) | To FirstEnergy | |||||||||||||||
| (In millions) | ||||||||||||||||||||
TE | ||||||||||||||||||||
| March 31, 2010 | $ | 132.5 | $ | 20.9 | $ | 12.9 | $ | 5.4 | $ | 7.5 | ||||||||||
| March 31, 2009 | 244.8 | 2.2 | 0.9 | (0.1 | ) | 1.0 | ||||||||||||||
| June 30, 2010 | 120.8 | 14.4 | 8.2 | 0.9 | 7.2 | |||||||||||||||
| June 30, 2009 | 226.2 | 10.1 | 9.8 | 3.4 | 6.4 | |||||||||||||||
| September 30, 2010 | 144.0 | 27.9 | 20.0 | 6.9 | 13.1 | |||||||||||||||
| September 30, 2009 | 213.5 | 10.2 | 7.0 | (0.1 | ) | 7.1 | ||||||||||||||
| December 31, 2010 | 119.4 | 18.5 | 9.6 | 4.4 | 5.2 | |||||||||||||||
December 31, 2009** | 149.4 | 23.8 | 14.2 | 4.7 | 9.5 | |||||||||||||||
Met-Ed | ||||||||||||||||||||
| March 31, 2010 | $ | 473.1 | $ | 34.8 | $ | 24.6 | $ | 12.3 | $ | 12.3 | ||||||||||
| March 31, 2009 | 429.7 | 37.7 | 28.4 | 11.7 | 16.6 | |||||||||||||||
| June 30, 2010 | 442.7 | 36.3 | 25.7 | 8.6 | 17.1 | |||||||||||||||
| June 30, 2009 | 377.6 | 27.8 | 17.0 | 7.0 | 10.0 | |||||||||||||||
| September 30, 2010 | 483.9 | 35.1 | 24.3 | 10.1 | 14.2 | |||||||||||||||
| September 30, 2009 | 445.5 | 24.2 | 13.1 | 2.3 | 10.7 | |||||||||||||||
| December 31, 2010 | 418.8 | 37.9 | 26.3 | 11.9 | 14.4 | |||||||||||||||
| December 31, 2009 | 436.2 | 37.2 | 25.6 | 7.6 | 18.2 | |||||||||||||||
Penelec | ||||||||||||||||||||
| March 31, 2010 | $ | 403.5 | $ | 50.0 | $ | 34.5 | $ | 17.2 | $ | 17.3 | ||||||||||
| March 31, 2009 | 388.6 | 44.2 | 31.8 | 13.1 | 18.7 | |||||||||||||||
| June 30, 2010 | 366.5 | 34.9 | 18.8 | 5.8 | 13.0 | |||||||||||||||
| June 30, 2009 | 331.7 | 36.0 | 25.1 | 10.2 | 14.8 | |||||||||||||||
| September 30, 2010 | 389.9 | 41.0 | 25.1 | 5.3 | 19.8 | |||||||||||||||
| September 30, 2009 | 355.5 | 32.3 | 21.8 | 6.0 | 15.8 | |||||||||||||||
| December 31, 2010 | 380.0 | 38.0 | 22.3 | 12.9 | 9.4 | |||||||||||||||
| December 31, 2009 | 373.1 | 49.4 | 32.4 | 16.4 | 16.1 | |||||||||||||||
JCP&L | ||||||||||||||||||||
| March 31, 2010 | $ | 703.7 | $ | 80.2 | $ | 52.8 | $ | 23.5 | $ | 29.2 | ||||||||||
| March 31, 2009 | 773.7 | 77.1 | 50.1 | 22.6 | 27.6 | |||||||||||||||
| June 30, 2010 | 720.6 | 111.7 | 83.4 | 33.5 | 49.9 | |||||||||||||||
| June 30, 2009 | 708.1 | 95.4 | 67.9 | 29.8 | 38.1 | |||||||||||||||
| September 30, 2010 | 968.5 | 175.7 | 147.3 | 64.4 | 82.9 | |||||||||||||||
| September 30, 2009 | 868.2 | 133.7 | 105.6 | 43.4 | 62.2 | |||||||||||||||
| December 31, 2010 | 634.3 | 85.9 | 56.9 | 26.9 | 30.1 | |||||||||||||||
| December 31, 2009 | 642.7 | 84.1 | 55.7 | 13.0 | 42.6 | |||||||||||||||
| ** | Includes a $2.5 million adjustment that increased net income in the fourth quarter of 2009 related to prior periods. (See Note 9 for description of adjustment). |
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22. PROPOSED MERGER WITH ALLEGHENY
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010 (Merger Agreement), with Element Merger Sub, Inc., a Maryland corporation, its wholly-owned subsidiary (Merger Sub) and Allegheny, a Maryland corporation. Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub would merge with and into Allegheny with Allegheny continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closing of the merger, each issued and outstanding share of Allegheny common stock, including grants of restricted common stock, would automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy, and Allegheny stockholders would own approximately 27% of the combined company. FirstEnergy would also assume all outstanding Allegheny debt.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, which was received on September 14, 2010; the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, which occurred on July 16, 2010. Approval of the merger was received from the VSCC on September 9, 2010. Approval from the FERC and from the PSCWV was received on December 16, 2010. Approval from the MDPSC was received on January 18, 2011. On January 7, 2011, we were notified by the DOJ that it had completed its review of the merger and closed its investigation. The proposed merger is also conditioned upon receipt of the approval of the PPUC. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny, and further provides for the payment of fees and expenses upon termination under specified circumstances.
FirstEnergy and Allegheny currently anticipate completing the merger in the first quarter of 2011. Although FirstEnergy and Allegheny believe that they will receive the required authorizations, approvals and consents to complete the merger, there can be no assurance as to the timing of these authorizations, approvals and consents or as to FirstEnergy’s and Allegheny’s ultimate ability to obtain such authorizations, consents or approvals (or any additional authorizations, approvals or consents which may otherwise become necessary) or that such authorizations, approvals or consents will be obtained on terms and subject to conditions satisfactory to Allegheny and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in connection with the merger.
In connection with the proposed merger, FirstEnergy recorded approximately $65 million ($47 million after tax) of merger transaction costs in the year ended December 31, 2010. These costs are expensed as incurred.
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| ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE |
None.
| ITEM 9A. | CONTROLS AND PROCEDURES — FIRSTENERGY |
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officers and Chief Financial Officers of FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec have reviewed and evaluated the registrants’ disclosure controls and procedures, as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e), as of the end date covered by this report. Based upon this evaluation, the respective Chief Executive Officer and Chief Financial Officer concluded that each registrant’s disclosure controls and procedures were effective as of December 31, 2010.
Management’s Report on Internal Control over Financial Reporting
Management is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934. Using the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in Internal Control — Integrated Framework, management conducted an evaluation of the effectiveness of each registrant’s internal control over financial reporting under the supervision of each registrant’s Chief Executive Officer and Chief Financial Officer. Based on that evaluation, management concluded that each registrant’s internal control over financial reporting was effective as of December 31, 2010. The effectiveness of FirstEnergy’s internal control over financial reporting, as of December 31, 2010, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included herein. The effectiveness of internal control over financial reporting of FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec, as of December 31, 2010, has not been audited by the registrants’ independent registered public accounting firm.
Changes in Internal Control over Financial Reporting
There were no changes in internal control over financial reporting during the fourth quarter of 2010 that have materially affected, or are reasonably likely to materially affect, internal control over financial reporting for each registrant.
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| ITEM 9B. | OTHER INFORMATION |
Signal Peak Mine Safety
FirstEnergy, through its FEV wholly-owned subsidiary, has a 50% interest in Global Mining Group LLC, a joint venture that owns Signal Peak which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup, Montana. The operation of the Mine is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act).
Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was enacted on July 21, 2010, contains new reporting requirements regarding mine safety, including, to the extent applicable, disclosing in periodic reports filed under the Securities Exchange Act of 1934 the receipt of certain notifications from the MSHA.
On November 19, 2010, Signal Peak received a letter from MSHA placing it on notice that the Mine has a potential pattern of violations of mandatory health or safety standards under Section 104(e) of the Mine Act. If implemented, Section 104(e) requires all subsequent violations designated as Significant and Substantial be issued as closure orders with all persons withdrawn from the affected area except those necessary to correct the violation.
In addition, Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended December 31, 2010:
| Signal | ||||
| Peak | ||||
| Number of significant and substantial violations of mandatory health or safety standards under 104* | 6 | |||
| Number of orders issued under 104(b)* | — | |||
| Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)* | 2 | |||
| Number of flagrant violations under 110(b)(2)* | — | |||
| Number of imminent danger orders issued under 107(a)* | — | |||
| MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern | 1 | |||
| Pending Mine Safety Commission legal actions (including any contested citations issued) | 1 | |||
| Number of mining-related fatalities | — | |||
| Total dollar value of proposed assessments | $ | 1,188 | ||
| * | References to sections under the Mine Act |
The inclusion of this information in this report is not an admission by FirstEnergy that it controls Signal Peak or that Signal Peak is FirstEnergy’s subsidiary for purposes of Section 1503 or for any other purpose.
More detailed information about the Mine, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Signal Peak operates the Mine under the MSHA identification number 2401950.
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PART III
| ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE |
The information required by Item 10, with respect to identification of FirstEnergy’s directors and with respect to reports required to be filed under Section 16 of the Securities Exchange Act of 1934, is incorporated herein by reference to FirstEnergy’s 2011 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934 and, with respect to identification of executive officers, to “Part I, Item 1. Business — Executive Officers” herein.
The Board of Directors, upon recommendation of the Corporate Governance and Audit Committees, has determined that Ernest J. Novak, Jr., an independent director, is the audit committee financial expert.
FirstEnergy makes available on its Web site at http://www.firstenergycorp.com/ir its Corporate Governance Policies and the charters for each of the following committees of the Board of Directors: Audit; Compensation; Corporate Governance; Finance; and Nuclear.
FirstEnergy has adopted a Code of Business Conduct, which applies to all employees, including the Chief Executive Officer, the Chief Financial Officer and the Chief Accounting Officer. In addition, the Board of Directors has its own Code of Business Conduct. These Codes can be found on the Web site provided in the previous paragraph.
| ITEM 11. | EXECUTIVE COMPENSATION |
The information required by Item 11 is incorporated herein by reference to FirstEnergy’s 2011 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
| ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS |
The information required by Item 12 is incorporated herein by reference to FirstEnergy’s 2011 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
| ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE |
The information required by Item 13 is incorporated herein by reference to FirstEnergy’s 2011 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
| ITEM 14. | PRINCIPAL ACCOUNTING FEES AND SERVICES |
A summary of the audit and audit-related fees rendered by PricewaterhouseCoopers LLP for the years ended December 31, 2010 and 2009 are as follows:
| Audit Fees(1) | Audit-Related Fees(2) | |||||||||||||||
| Company | 2010 | 2009 | 2010 | 2009 | ||||||||||||
| (In thousands) | ||||||||||||||||
| FES | $ | 1,181 | $ | 991 | $ | — | $ | — | ||||||||
| OE | 636 | 1,019 | — | — | ||||||||||||
| CEI | 542 | 734 | — | — | ||||||||||||
| TE | 589 | 626 | — | — | ||||||||||||
| JCP&L | 589 | 715 | — | — | ||||||||||||
| Met-Ed | 495 | 607 | — | — | ||||||||||||
| Penelec | 495 | 613 | — | — | ||||||||||||
| FirstEnergy and other subsidiaries | 976 | 690 | 548 | — | ||||||||||||
| Total FirstEnergy | $ | 5,503 | $ | 5,995 | $ | 548 | $ | — | ||||||||
| (1) | Professional services rendered for the audits of FirstEnergy’s annual financial statements and reviews of financial statements included in FirstEnergy’s Quarterly Reports on Form 10-Q and for services in connection with statutory and regulatory filings or engagements, including comfort letters and consents for financings and filings made with the SEC. | |
| (2) | Professional services rendered in 2010 related to due diligence activities in connection with the proposed acquisition of Allegheny. |
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Tax and Other Fees
PricewaterhouseCoopers LLP billed to FirstEnergy and its subsidiaries $134,000 for tax services and no fees for other services in 2010 — there were no other fees billed for tax or other services in 2009. Tax services rendered in 2010 related to the preparation and support of Signal Peak and Global Rail Group tax returns.
Additional information required by this item is incorporated herein by reference to FirstEnergy’s 2011 Proxy Statement filed with the SEC pursuant to Regulation 14A under the Securities Exchange Act of 1934.
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PART IV
| ITEM 15. | EXHIBITS, FINANCIAL STATEMENT SCHEDULES |
(a) The following documents are filed as a part of this report on Form 10-K:
1. Financial Statements:
Management’s Report on Internal Control Over Financial Reporting for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec is listed under Item 8 herein.
Reports of Independent Registered Public Accounting Firm for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8 herein.
The financial statements filed as a part of this report for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are listed under Item 8 herein.
2. Financial Statement Schedules:
Reports of Independent Registered Public Accounting Firm as to Schedules for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on pages 132, 133, 134, 135, 136, 137, 138 and 139.
Schedule II — Consolidated Valuation and Qualifying Accounts for FirstEnergy Corp., FES, OE, CEI, TE, JCP&L, Met-Ed, and Penelec are included herein on pages 306, 307, 308, 309, 310, 311, 312 and 313.
3. Exhibits — FirstEnergy
| Exhibit | |||
| Number | |||
| 2-1 | † | Agreement and Plan of Merger, dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc. (incorporated by reference to FE’s Form 8-K filed February 11, 2010, Exhibit 2.1, File No. 333-21011) | |
| 3-1 | Amended Articles of Incorporation of FirstEnergy Corp. (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 3-1, File No. 333-21011) | ||
| 3-2 | FirstEnergy Corp. Amended Code of Regulations. (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 3.1, File No. 333-21011) | ||
| 4-1 | Indenture, dated November 15, 2001, between FirstEnergy Corp. and The Bank of New York Mellon, as Trustee. (incorporated by reference to FE’s Form S-3 filed September 21, 2001, Exhibit 4(a), File No. 333-69856) | ||
| (B) 10-1 | FirstEnergy Corp. 2007 Incentive Plan, effective May 15, 2007. (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10.1, File No. 333-21011) | ||
| (B) 10-2 | Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of January 1, 2005 and ratified as of September 18, 2007. (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10.2, File No. 333-21011) | ||
| (B) 10-3 | FirstEnergy Corp. Supplemental Executive Retirement Plan, amended January 1, 1999. (incorporated by reference to FE’s Form 10-K filed March 20, 2000, Exhibit 10-4, File No. 333-21011) | ||
| (B) 10-4 | Stock Option Agreement between FirstEnergy Corp. and officers dated November 22, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-3, File No. 333-21011) | ||
| (B) 10-5 | Stock Option Agreement between FirstEnergy Corp. and officers dated March 1, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-4, File No. 333-21011) | ||
| (B) 10-6 | Stock Option Agreement between FirstEnergy Corp. and director dated January 1, 2000. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-5, File No. 333-21011) | ||
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| Exhibit | |||
| Number | |||
| (B) 10-7 | Stock Option Agreement between FirstEnergy Corp. and two directors dated January 1, 2001. (incorporated by reference to FE’s Form 10-K filed March 28, 2001, Exhibit 10-6, File No. 333-21011) | ||
| (B) 10-8 | Stock Option Agreements between FirstEnergy Corp. and One Director dated January 1, 2002. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-5, File No. 333-21011) | ||
| (B) 10-9 | FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of January 1, 2005 and ratified as of September 18, 2007. (incorporated by reference to FE’s 10-Q filed October 31, 2007, Exhibit 10.2, File No. 333-21011) | ||
| (B) 10-10 | Executive Incentive Compensation Plan-Tier 2. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-7, File No. 333-21011) | ||
| (B) 10-11 | Executive Incentive Compensation Plan-Tier 3. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-8, File No. 333-21011) | ||
| (B) 10-12 | Executive Incentive Compensation Plan-Tier 4. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-9, File No. 333-21011) | ||
| (B) 10-13 | Executive Incentive Compensation Plan-Tier 5. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-10, File No. 333-21011) | ||
| (B) 10-14 | Amendment to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, effective April 5, 2001. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-11, File No. 333-21011) | ||
| (B) 10-15 | Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-12, File No. 333-21011) | ||
| (B) 10-16 | GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (incorporated by reference to FE’s Form 10-K filed April 1, 2002, Exhibit 10-13, File No. 333-21011, File No. 333-21011) | ||
| (B) 10-17 | Executive and Director Stock Option Agreement dated June 11, 2002. (incorporated by reference to FE’s Form 10-K, Exhibit 10-1, File No. 333-21011) | ||
| (B) 10-18 | Director Stock Option Agreement. (incorporated by reference to FE’s Form 10-K filed March 26, 2003, Exhibit 10-2, File No. 333-21011) | ||
| (B) 10-19 | Executive Incentive Compensation Plan 2002. (incorporated by reference to FE’s Form 10-K filed March 26, 2003, Exhibit 10-28, File No. 333-21011) | ||
| (B) 10-20 | GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries as amended and restated to reflect amendments through June 3, 1999. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-V, File No. 001-06047) | ||
| (B) 10-21 | Form of 1998 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-Q, File No. 001-06047) | ||
| (B) 10-22 | Form of 1999 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No. 001-06047) | ||
| (B) 10-23 | Form of 2000 Stock Option Agreement under the GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-W, File No. 001-06047) | ||
| (B) 10-24 | Deferred Remuneration Plan for Outside Directors of GPU, Inc. as amended and restated effective August 8, 2000. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-O, File No. 001-06047) | ||
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| Exhibit | |||
| Number | |||
| (B) 10-25 | Retirement Plan for Outside Directors of GPU, Inc. as amended and restated as of August 8, 2000. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-N, File No. 001-06047) | ||
| (B) 10-26 | Forms of Estate Enhancement Program Agreements entered into by certain former GPU directors. (incorporated by reference to GPU, Inc. Form 10-K filed March 20, 2000, Exhibit 10-JJ, File No. 001-06047) | ||
| (B) 10-27 | Employment Agreement for Richard R. Grigg dated February 26, 2008, (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10.5, File No. 333-21011), as amended on January 29, 2010. | ||
| (B) 10-28 | Stock Option Agreement between FirstEnergy Corp. and an officer dated August 20, 2004. (incorporated by reference to FE’s Form 10-Q filed November 4, 2004, Exhibit 10-42, File No. 333-21011) | ||
| (B) 10-29 | Executive Bonus Plan between FirstEnergy Corp. and Officers effective November 3, 2004. (incorporated by reference to FE’s Form 10-Q filed November 4, 2004, Exhibit 10-44, File No. 333-21011) | ||
| 10-30 | Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10-1, File No. 333-21011) | ||
| (C) 10-32 | Form of Guaranty Agreement dated as of April 3, 2006 by FirstEnergy Corp. in favor of the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent, under the related Letter of Credit and Reimbursement Agreement. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-1, File No. 333-21011) | ||
| (B) 10-33 | Form of Restricted Stock Agreement between FirstEnergy Corp. and A. J. Alexander, dated February 27, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-6, File No. 333-21011) | ||
| (B) 10-34 | Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and A. J. Alexander, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-7, File No. 333-21011) | ||
| (B) 10-35 | Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and named executive officers, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-8, File No. 333-21011) | ||
| (B) 10-36 | Form of Restricted Stock Unit Agreement (Performance Adjusted) between FirstEnergy Corp. and R. H. Marsh, dated March 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-9, File No. 333-21011) | ||
| (B) 10-38 | FirstEnergy Corp. Supplemental Executive Retirement Plan as amended September 18, 2007. (incorporated by reference to FE’s Form 10-Q filed October 31, 2007, Exhibit 10.2, File No. 333-21011) | ||
| (B) 10-39 | Employment Agreement between FirstEnergy Corp. and Gary R. Leidich, dated February 26, 2008 (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-88, File No. 333-21011), as amended on January 29, 2010. (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-39, File No. 333-21011) | ||
| (B) 10-40 | Form of Restricted Stock Unit Agreement for Gary R. Leidich (per Employment Agreement dated February 26, 2008). (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-90, File No. 333-21011) | ||
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| Exhibit | |||
| Number | |||
| (B) 10-41 | Form of Restricted Stock Agreement Amendment for Gary R. Leidich dated February 26, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-91, File No. 333-21011) | ||
| (B) 10-42 | Form of Restricted Stock Unit Agreement for Richard R. Grigg (per Employment Agreement dated February 26, 2008). (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-92, File No. 333-21011) | ||
| (B) 10-43 | Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 3, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-93, File No. 333-21011) | ||
| (B) 10-44 | Form of 2008-2010 Performance Share Award Agreement effective January 1, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-94, File No. 333-21011) | ||
| (B) 10-46 | Form of 2009-2011 Performance Share Award Agreement effective January 1, 2009 (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10-48, File No. 333-21011) | ||
| (B) 10-47 | Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 2, 2009 (incorporated by reference to FE’s Form 10-K filed February 25, 2009, Exhibit 10-49, File No. 333-21011) | ||
| (B) 10-48 | Form of 2010-2012 Performance Share Award Agreement effective January 1, 2010 (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-48, File No. 333-21011) | ||
| (B) 10-49 | Form of Performance-Adjusted Restricted Stock Unit Award Agreement as of March 8, 2010 (incorporated by reference to FE’s Form 10-K filed February 19, 2010, Exhibit 10-49, File No. 333-21011) | ||
| (B) 10-50 | Form of Director Indemnification Agreement (incorporated by reference to FE’s 10-Q filed May 7, 2009, Exhibit 10.1, File No. 333-21011) | ||
| (B) 10-51 | Form of Management Director Indemnification Agreement (incorporated by reference to FE’s 10-Q filed May 7, 2009, Exhibit 10.2, File No. 333-21011) | ||
| (B) 10-52 | Amended FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, amended and restated as of September 21, 2010 (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.1, File No. 333-21011) | ||
| (B) 10-53 | Amended FirstEnergy Corp. Executive Deferred Compensation Plan, amended and restated as of September 21, 2010 (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.2, File No. 333-21011) | ||
| 10-54 | Signal Peak Credit Agreement, including the forms of the guaranty and pledge agreement attached as exhibits thereto (incorporated by reference to FE’s 10-Q filed October 26, 2010, Exhibit 10.3, File No. 333-21011) | ||
| (A) 12-1 | Consolidated ratios of earnings to fixed charges. | ||
| (A) 21 | List of Subsidiaries of the Registrant at December 31, 2010. | ||
| (A) 23-1 | Consent of Independent Registered Public Accounting Firm. | ||
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | ||
| † | Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The Registrant will furnish the omitted schedules to the Securities and Exchange Commission upon request by the Commission | ||
| (A) | Provided herein in electronic format as an exhibit. | ||
| (B) | Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K. | ||
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| Exhibit | |||
| Number | |||
| (C) | Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp. | ||
3. Exhibits — FES
| 3-1 | Articles of Incorporation of FirstEnergy Solutions Corp., as amended August 31, 2001. (incorporated by reference to FES’ Form S-4 filed August 6, 2007, Exhibit 3.1, File No. 333-145140-01) | ||
| 3-2 | Amended and Restated Code of Regulations of FirstEnergy Solutions Corp. effective as of August 26, 2009 (incorporated by reference to FES’ Form 8-K filed August 7, 2009, Exhibit 3.4, File No. 000-53742) | ||
| 4-1 | Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee (incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1, File No. 333-145140-01) | ||
| 4-1 | (a) | First Supplemental Indenture dated as of June 25, 2008 (including Form of First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and Form First Mortgage Bonds, Guarantee Series B of 2008 due 2009). (incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(a), File No. 333-145140-01) | |
| 4-1 | (b) | Second Supplemental Indenture dated as of March 1, 2009 (including Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2023). (incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(b), File No. 333-145140-01) | |
| 4-1 | (c) | Third Supplemental Indenture dated as of March 31, 2009 (including Form of First Mortgage Bonds, Collateral Series A of 2009 due 2011). (incorporated by reference to FES’ 10-Q filed May 7, 2009, Exhibit 4.1(c), File No. 333-145140-01) | |
| 4-1 | (d) | Fourth Supplemental Indenture, dated as of June 1, 2009 (including Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2018, Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2029, Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2029, Form of First Mortgage Bonds, Collateral Series B of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series C of 2009 due 2011). (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.3, File No. 333-145140-01) | |
| 4-1 | (e) | Fifth Supplemental Indenture, dated as of June 30, 2009 (including Form of First Mortgage Bonds, Guarantee Series F of 2009 due 2047, Form of First Mortgage Bonds, Guarantee Series G of 2009 due 2018 and Form of First Mortgage Bonds, Guarantee Series H of 2009 due 2018). (incorporated by reference to FES’ Form 8-K filed July 6, 2009, Exhibit 4.2, File No. 333-145140-01) | |
| 4-1 | (f) | Sixth Supplemental Indenture, dated as of December 1, 2009 (including Form of First Mortgage Bonds, Collateral Series D of 2009 due 2012 (incorporated by reference to FES’ Form 8-K filed December 4, 2009, Exhibit 4.2, File No. 000-53742) | |
| 4-2 | Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, by and between FirstEnergy Nuclear Generation Corp. and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.1, File No. 333-145140-01) |
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| 4-2 | (a) | First Supplemental Indenture, dated as of June 15, 2009 (including Form of First Mortgage Bonds, Guarantee Series A of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series B of 2009 due 2011, Form of First Mortgage Bonds, Collateral Series A of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series B of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series C of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series D of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series E of 2009 due 2010, Form of First Mortgage Bonds, Collateral Series F of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series G of 2009 due 2011). (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 4.2(i), File No. 333-145140-01) | |
| 4-2 | (b) | Second Supplemental Indenture, dated as of June 30, 2009 (including Form of First Mortgage Bonds, Guarantee Series C of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series D of 2009 due 2033, Form of First Mortgage Bonds, Guarantee Series E of 2009 due 2033, Form of First Mortgage Bonds, Collateral Series H of 2009 due 2011, Form of First Mortgage Bonds, Collateral Series I of 2009 due 2011 and Form of First Mortgage Bonds, Collateral Series J of 2009 due 2010). (incorporated by reference to FES’ Form 8-K filed July 6, 2009, Exhibit 4.1(f), File No. 333-145140-01) | |
| 4-2 | (c) | Third Supplemental Indenture, dated as of December 1, 2009 (including Form of First Mortgage Bonds, Collateral Series K of 2009 due 2012). (incorporated by reference to FES’ Form 8-K filed December 4, 2009, Exhibit 4.1, File No. 000-53742) | |
| 4-3 | Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES’ Form 8-K filed August 7, 2009, Exhibit 4.1, File No. 000-53742) | ||
| 4-3 | (a) | First Supplemental Indenture, dated as of August 1, 2009 (including Form of 4.80% Senior Notes due 2015, Form of 6.05% Senior Notes due 2021 and Form of 6.80% Senior Notes due 2039). (incorporated by reference to FES’ Form 8-K filed August 7, 2009, Exhibit 4.2, File No. 000-53742) | |
| 10-1 | Form of 6.85% Exchange Certificate due 2034. (incorporated by reference to FES’ Form S-4 filed August 6, 2007, Exhibit 4.1, File No. 333-145140-01) | ||
| 10-2 | Guaranty of FirstEnergy Solutions Corp., dated as of July 1, 2007. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-9, File No. 333-21011) | ||
| 10-3 | Indenture of Trust, Open-End Mortgage and Security Agreement, dated as of July 1, 2007, between the applicable Lessor and The Bank of New York Trust Company, N.A., as Indenture Trustee. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-3, File No. 333-21011) | ||
| 10-4 | 6.85% Lessor Note due 2034. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-3, File No. 333-21011) | ||
| 10-6 | Participation Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., as Lessee, FirstEnergy Solutions Corp., as Guarantor, the applicable Lessor, U.S. Bank Trust National Association, as Trust Company, the applicable Owner Participant, The Bank of New York Trust Company, N.A., as Indenture Trustee, and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-1, File No. 333-21011) | ||
| 10-7 | Trust Agreement, dated as of June 26, 2007, between the applicable Owner Participant and U.S. Bank Trust National Association, as Owner Trustee. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-2, File No. 333-21011) | ||
| 10-8 | Pass Through Trust Agreement, dated as of June 26, 2007, among FirstEnergy Generation Corp., FirstEnergy Solutions Corp., and The Bank of New York Trust Company, N.A., as Pass Through Trustee. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-12, File No. 333-21011) |
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| 10-9 | Bill of Sale and Transfer, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-5, File No. 333-21011) | |
| 10-10 | Facility Lease Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-6, File No. 333-21011) | |
| 10-11 | Site Lease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-7, File No. 333-21011) | |
| 10-12 | Site Sublease, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-8, File No. 333-21011) | |
| 10-13 | Support Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp. and the applicable Lessor. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-10, File No. 333-21011) | |
| 10-14 | Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-11, File No. 333-21011) | |
| 10-15 | OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 333-21011) | |
| 10-16 | CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.6, File No. 333-21011) | |
| 10-17 | TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to FE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 333-21011) | |
| 10-18 | Agreement, dated August 26, 2005, by and between FirstEnergy Generation Corp. and Bechtel Power Corporation. (incorporated by reference to FE’s Form 10-Q filed November 2, 2005, Exhibit 10-2, File No. 333-21011) | |
| 10-19 | CEI Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.15, File No. 333-145140-01) | |
| 10-20 | CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.16, File No. 333-145140-01) | |
| 10-21 | OE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.17, File No. 333-145140-01) | |
| 10-22 | OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File No. 333-145140-01) | |
| 10-23 | Amendment No. 1 to OE Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.19, File No. 333-145140-01) | |
| 10-24 | PP Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.20, File No. 333-145140-01) |
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| 10-25 | PP Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Pennsylvania Power Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.21, File No. 333-145140-01) | |
| 10-26 | Amendment No. 1 to PP Fossil Security Agreement, dated as of June 30, 2007, between FirstEnergy Generation Corp. and Pennsylvania Power Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.22, File No. 333-145140-01) | |
| 10-27 | TE Fossil Note, dated October 24, 2005, of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.23, File No. 333-145140-01) | |
| 10-28 | TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.24, File No. 333-145140-01) | |
| 10-29 | CEI Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.25, File No. 333-145140-01) | |
| 10-30 | CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.26, File No. 333-145140-01) | |
| 10-31 | OE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.27, File No. 333-145140-01) | |
| 10-32 | PP Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.28, File No. 333-145140-01) | |
| 10-33 | TE Nuclear Note, dated December 16, 2005, of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.29, File No. 333-145140-01) | |
| 10-34 | TE Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.30, File No. 333-145140-01) | |
| 10-35 | Mansfield Power Supply Agreement, dated August 10, 2006, among The Cleveland Electric Illuminating Company, The Toledo Edison Company and FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.31, File No. 333-145140-01) | |
| 10-36 | Nuclear Power Supply Agreement, dated August 10, 2006, between FirstEnergy Nuclear Generation Corp. and FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.32, File No. 333-145140-01) | |
| 10-37 | Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.34, File No. 333-145140-01) | |
| 10-38 | GENCO Power Supply Agreement, dated January 1, 2007, between FirstEnergy Generation Corp. and FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.36, File No. 333-145140-01) | |
| 10-39 | Form of Guaranty dated as of March 2, 2007, between FirstEnergy Corp., as Guarantor, and Morgan Stanley Senior Funding, Inc., as Lender under the U.S. $250,000,000 Credit Agreement, dated as of March 2, 2007, with FirstEnergy Solutions Corp., as Borrower. (incorporated by reference to FE’s Form 10-Q filed May 9, 2007, Exhibit 10-23, File No. 333-145140-01) |
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| 10-40 | Guaranty, dated as of March 26, 2007, by FirstEnergy Generation Corp. on behalf of FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.39, File No. 333-145140-01) | |
| 10-41 | Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.40, File No. 333-145140-01) | |
| 10-42 | Guaranty, dated as of March 26, 2007, by FirstEnergy Solutions Corp. on behalf of FirstEnergy Nuclear Generation Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.41, File No. 333-145140-01) | |
| 10-43 | Guaranty, dated as of March 26, 2007, by FirstEnergy Nuclear Generation Corp. on behalf of FirstEnergy Solutions Corp. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.42, File No. 333-145140-01) | |
| (B) 10-44 | Form of Guaranty Agreement dated as of December 16, 2005 between FirstEnergy Corp. and FirstEnergy Solutions Corp. in Favor of Barclays Bank PLC as Administrative Agent for the Banks. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-58, File No. 333-21011) | |
| (B) 10-45 | Form of Trust Indenture dated as of December 1, 2005 between Ohio Water Development Authority and JP Morgan Trust Company related to issuance of FirstEnergy Nuclear Generation Corp. pollution control revenue refunding bonds. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-59, File No. 333-21011) | |
| 10-46 | GENCO Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-60, File No. 333-21011) | |
| 10-47 | Nuclear Power Supply Agreement dated as of October 14, 2005 between FirstEnergy Nuclear Generation Corp. (Seller) and FirstEnergy Solutions Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-61, File No. 333-21011) | |
| (B) 10-48 | Form of Letter of Credit and Reimbursement Agreement Dated as of December 16, 2005 among FirstEnergy Nuclear Generation Corp., and the Participating Banks and Barclays Bank PLC. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-62, File No. 333-21011) | |
| (B) 10-49 | Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., dated as of December 1, 2005. (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-63, File No. 333-21011) | |
| 10-50 | Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and the Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-64, File No. 333-21011) | |
| 10-51 | Mansfield Power Supply Agreement dated as of October 14, 2005 between Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to FE’s Form 10-K filed March 3, 2006, Exhibit 10-65, File No. 333-21011) | |
| (C) 10-54 | Form of Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 among FirstEnergy Generation Corp., the Participating Banks, Barclays Bank PLC, as administrative agent and fronting bank, and KeyBank National Association, as syndication agent. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-2, File No. 333-21011) |
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| (C) 10-54 | (a) | Form of Amendment No. 2 to Letter of Credit and Reimbursement Agreement, dated as of June 12, 2009, by and among FirstEnergy Generation Corp., FirstEnergy Corp. and FirstEnergy Solutions Corp., as guarantors, the banks party thereto, Barclays Bank PLC, as fronting Bank and administrative agent and KeyBank National Association, as syndication agent, to Letter of Credit and Reimbursement Agreement dated as of April 3, 2006 (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 10.2, File No. 333-145140-01) | |
| (C) 10-55 | Form of Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-3, File No. 333-21011) | ||
| (C) 10-56 | Form of Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006. (incorporated by reference to FE’s Form 10-Q filed May 9, 2006, Exhibit 10-4, File No. 333-21011) | ||
| (D) 10-57 | Form of Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Trust Company, N.A. as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project). (incorporated by reference to FE’s Form 10-K filed February 28, 2007, Exhibit 10-77, File No. 333-21011) | ||
| (D) 10-58 | Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006. (incorporated by reference to FE’s Form 10-K filed February 28, 2007, Exhibit 10-80, File No. 333-21011) | ||
| 10-59 | Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10.1, File No. 333-21011) | ||
| 10-61 | Amendment to Agreement for Engineering, Procurement and Construction of Air Quality Control Systems by and between FirstEnergy Generation Corp. and Bechtel Power Corporation dated September 14, 2007. (incorporated by reference to FE’s Form 10-Q filed October 31, 2007, Exhibit 10.1, File No. 333-21011) | ||
| 10-61 | Asset Purchase Agreement by and between Calpine Corporation, as Seller, and FirstEnergy Generation Corp., as Buyer, dated as of January 28, 2008. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-48, File No. 333-21011) | ||
| 10-63 | Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to FE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 333-21011) | ||
| 10-64 | Surplus Margin Guaranty, dated as of June 16, 2009, made by FirstEnergy Nuclear Generation Corp. in favor of The Cleveland Electric Illuminating Company, The Toledo Edison Company and Ohio Edison Company (incorporated by reference to FES’ Form 8-K filed June 19, 2009, Exhibit 10.3, File No. 333-145140-01) | ||
| (A) 12-2 | Consolidated ratios of earnings to fixed charges. | ||
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. |
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| (A) | Provided herein in electronic format as an exhibit. | |
| (B) | Four substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to four other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, the Ohio Air Quality Authority and Beaver County Industrial Development Authority, Pennsylvania, relating to pollution control notes of FirstEnergy Nuclear Generation Corp. | |
| (C) | Three substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to three other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority and the Beaver County Industrial Development Authority relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp. | |
| (D) | Seven substantially similar agreements, each dated as of the same date, were executed and delivered by the registrant and its affiliates with respect to one other series of pollution control revenue refunding bonds issued by the Ohio Water Development Authority, three other series of pollution control bonds issued by the Ohio Air Quality Development Authority and the three other series of pollution control bonds issued by the Beaver County Industrial Development Authority, relating to pollution control notes of FirstEnergy Generation Corp. and FirstEnergy Nuclear Generation Corp. |
3. Exhibits — OE
| 2-1 | Agreement and Plan of Merger, dated as of September 13, 1996, between Ohio Edison Company and Centerior Energy Corporation. (incorporated by reference to OE’s Form 8—K filed September 17, 1996, Exhibit 2—1, File No. 001-02578) | ||
| 3-1 | Amended and Restated Articles of Incorporation of Ohio Edison Company, Effective December 18, 2007. (incorporated by reference to OE’s Form 10-K filed February 29, 2008, Exhibit 3-4, File No. 001-02578) | ||
| 3-2 | Amended and Restated Code of Regulations of Ohio Edison Company, dated December 14, 2007. (incorporated by reference to OE’s Form 10-K filed February 29, 2008, Exhibit 3-5, File No. 001-02578) | ||
| 4-1 | General Mortgage Indenture and Deed of Trust dated as of January 1, 1998 between Ohio Edison Company and the Bank of New York, as Trustee, as amended and supplemented by Supplemental Indentures: (incorporated by reference to OE’s Form S-3 filed June 5, 1996, Exhibit 4(b), File No. 333-05277) | ||
| 4-1 | (a) | February 1, 2003 (incorporated by reference to OE’s Form 10-K filed March 15, 2004, Exhibit 4-4, File No. 001-02578) | |
| 4-1 | (b) | March 1, 2003 (incorporated by reference to OE’s Form 10-K filed March 15, 2004, Exhibit 4-5, File No. 001-02578) | |
| 4-1 | (c) | August 1, 2003 (incorporated by reference to OE’s Form 10-K filed March 15, 2004, Exhibit 4-6, File No. 001-02578) | |
| 4-1 | (d) | June 1, 2004 (incorporated by reference to OE’s Form 10-K filed March 10, 2005, Exhibit 4-4, File No. 001-02578) | |
| 4-1 | (e) | December 1, 2004 (incorporated by reference to OE’s Form 10-K filed March 10, 2005, Exhibit 4-4, File No. 001-02578) | |
| 4-1 | (f) | April 1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-4, File No. 001-02578) | |
| 4-1 | (g) | April 15, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-5, File No. 001-02578) | |
| 4-1 | (h) | June 1, 2005 (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 4-6, File No. 001-02578) | |
| 4-1 | (i) | October 1, 2008 (incorporated by reference to OE’s Form 8-K filed October 22, 2008, Exhibit 4.1, File No. 001-02578) | |
| 4-2 | Indenture dated as of April 1, 2003 between Ohio Edison Company and The Bank of New York, as Trustee. (incorporated by reference to OE’s Form 10-K filed March 15, 2004, Exhibit 4-3, File No. 001-02578) |
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| 4-2 | (a) | Officer’s Certificate (including the forms of the 6.40% Senior Notes due 2016 and the 6.875% Senior Notes due 2036), dated June 21, 2006. (incorporated by reference to OE’s Form 8-K filed June 27, 2006, Exhibit 4, File No. 001-02578) | |
| 10-1 | Amendment No. 4 dated as of July 1, 1985 to the Bond Guaranty dated as of October 1, 1973, as amended, by the CAPCO Companies to National City Bank as Bond Trustee. (incorporated by reference to 1985 Form 10-K, Exhibit 10-30) | ||
| 10-2 | Amendment No. 5 dated as of May 1, 1986, to the Bond Guaranty by the CAPCO Companies to National City Bank as Bond Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 10-33) | ||
| 10-3 | Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-33) | ||
| 10-4 | Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-34) | ||
| (B) 10-5 | Ohio Edison System Executive Supplemental Life Insurance Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-44, File No. 001-02578) | ||
| (B) 10-6 | Ohio Edison System Executive Incentive Compensation Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-45, File No. 001-02578) | ||
| (B) 10-7 | Ohio Edison System Restated and Amended Supplemental Executive Retirement Plan. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-47, File No. 001-02578) | ||
| (B) 10-8 | Form of Amendment, effective November 7, 2001, to GPU, Inc. 1990 Stock Plan for Employees of GPU, Inc. and Subsidiaries, Deferred Remuneration Plan for Outside Directors of GPU, Inc., and Retirement Plan for Outside Directors of GPU, Inc. (incorporated by reference to OE’s Form 10-K filed April 1, 2002, Exhibit 10-26, File No. 001-02578) | ||
| (B) 10-9 | GPU, Inc. Stock Option and Restricted Stock Plan for MYR Group, Inc. Employees. (incorporated by reference to OE’s Form 10-K filed April 1, 2002, Exhibit 10-27, File No. 001-02578)) | ||
| (B) 10-10 | Severance pay agreement between Ohio Edison Company and A. J. Alexander. (incorporated by reference to OE’s Form 10-K filed March 19, 1996, Exhibit 10-50, File No. 001-02578) | ||
| (C) 10-11 | Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-1) | ||
| (C) 10-12 | Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company (now The Bank of New York), as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-46) | ||
| (C) 10-13 | Amendment No. 3 dated as of May 16, 1988 to Participation Agreement dated as of March 16, 1987, as amended among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-47) |
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| (C) 10-14 | Amendment No. 4 dated as of November 1, 1991 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-47) | |
| (C) 10-15 | Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987, as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-49) | |
| (C) 10-16 | Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-50) | |
| (C) 10-17 | Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended, among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-54, File No. 001-02578)) | |
| (C) 10-18 | Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-2) | |
| (C) 10-19 | Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1997 between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-49) | |
| (C) 10-20 | Amendment No. 2 dated as of November 1, 1991, to Facility Lease dated as of March 16, 1987, between The First National Bank of Boston, as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-50) | |
| (C) 10-21 | Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as March 16, 1987 as amended, between The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited partnership, as Owner Participant and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-54) | |
| (C) 10-22 | Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-59, File No. 001-02578)) | |
| (C) 10-23 | Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended, between, The First National Bank of Boston, as Owner Trustee, with Perry One Alpha Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-60, File No. 001-02578) | |
| (C) 10-24 | Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, Lessee, and The First National Bank of Boston, Owner Trustee under a Trust dated March 16, 1987 with Chase Manhattan Realty Leasing Corporation, required by Section 3(d) of the Facility Lease. (incorporated by reference to 1986 Form 10-K, Exhibit 28-3) | |
| (C) 10-25 | Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with the Owner Participant, Tenant. (incorporated by reference to 1986 Form 10-K, Exhibit 28-4) |
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| (C) 10-26 | Trust Agreement dated as of March 16, 1987 between Perry One Alpha Limited Partnership, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1986 Form 10-K, Exhibit 28-5) | |
| (C) 10-27 | Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of March 16, 1987 with Perry One Alpha Limited Partnership, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-6) | |
| (C) 10-28 | Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-55) | |
| (C) 10-29 | Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-56) | |
| (C) 10-30 | Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-7) | |
| (C) 10-31 | Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to 1991 Form 10-K, Exhibit 10-58) | |
| (C) 10-32 | Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-69, File No. 001-02578) | |
| (C) 10-33 | Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Perry One, Inc. and PARock Limited Partnership and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-70, File No. 001-02578) | |
| (C) 10-34 | Partial Mortgage Release dated as of March 19, 1987 under the Indenture between Ohio Edison Company and Bankers Trust Company, as Trustee, dated as of the 1st day of August 1930. (incorporated by reference to 1986 Form 10-K, Exhibit 28-8) | |
| (C) 10-35 | Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-9) | |
| (C) 10-36 | Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, and Ohio Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-10) | |
| (C) 10-37 | Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership. (incorporated by reference to 1986 Form 10-K, Exhibit 28-11) | |
| (C) 10-38 | Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Grantee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-12) |
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| 10-39 | Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Hereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-13) | |
| 10-40 | Amendment No. 1 dated as of September 1, 1987 to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, The Original Loan Participants Listed in Schedule 1 thereto, as Original Loan Participants, PNPP Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-65) | |
| 10-41 | Amendment No. 4 dated as of November 1, 1991, to Participation Agreement dated as of March 16, 1987 among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-66) | |
| 10-42 | Amendment No. 5 dated as of November 24, 1992 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-71) | |
| 10-43 | Amendment No. 6 dated as of January 12, 1993 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-80, File No. 001-02578) | |
| 10-44 | Amendment No. 7 dated as of October 12, 1994 to Participation Agreement dated as of March 16, 1987 as amended among Security Pacific Capital Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, File No. 001-02578) | |
| 10-45 | Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, Lessor, and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-14) | |
| 10-46 | Amendment No. 1 dated as of September 1, 1987 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-68) | |
| 10-47 | Amendment No. 2 dated as of November 1, 1991 to Facility Lease dated as of March 16, 1987 between The First National Bank of Boston as Owner Trustee, Lessor and Ohio Edison Company, Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-69) | |
| 10-48 | Amendment No. 3 dated as of November 24, 1992 to Facility Lease dated as of March 16, 1987, as amended, between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-75) | |
| 10-49 | Amendment No. 4 dated as of January 12, 1993 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-76) |
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| 10-50 | Amendment No. 5 dated as of October 12, 1994 to Facility Lease dated as of March 16, 1987 as amended between, The First National Bank of Boston, as Owner Trustee, with Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-87, File No. 001-02578) | |
| 10-51 | Letter Agreement dated as of March 19, 1987 between Ohio Edison Company, as Lessee, and The First National Bank of Boston, as Owner Trustee under a Trust, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, required by Section 3(d) of the Facility Lease. (incorporated by reference to 1986 Form 10-K, Exhibit 28-15) | |
| 10-52 | Ground Lease dated as of March 16, 1987 between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Perry One Alpha Limited Partnership, Tenant. (incorporated by reference to 1986 Form 10-K, Exhibit 28-16) | |
| 10-53 | Trust Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1986 Form 10-K, Exhibit 28-17) | |
| 10-54 | Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-18) | |
| 10-55 | Supplemental Indenture No. 1 dated as of September 1, 1987 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and Irving Trust Company (now The Bank of New York), as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-74) | |
| 10-56 | Supplemental Indenture No. 2 dated as of November 1, 1991 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee and The Bank of New York, as Indenture Trustee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-75) | |
| 10-57 | Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-19) | |
| 10-58 | Amendment No. 1 dated as of November 1, 1991 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to 1991 Form 10-K, Exhibit 10-77) | |
| 10-59 | Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-96, File No. 001-02578) | |
| 10-60 | Amendment No. 3 dated as of October 12, 1994 to Tax Indemnification Agreement dated as of March 16, 1987 between Security Pacific Capital Leasing Corporation and Ohio Edison Company. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-97, File No. 001-02578) | |
| 10-61 | Assignment, Assumption and Further Agreement dated as of March 16, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-20) | |
| 10-62 | Additional Support Agreement dated as of March 16, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, and Ohio Edison Company. (incorporated by reference to 1986 Form 10-K, Exhibit 28-21) |
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| 10-63 | Bill of Sale, Instrument of Transfer and Severance Agreement dated as of March 19, 1987 between Ohio Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Buyer. (incorporated by reference to 1986 Form 10-K, Exhibit 28-22) | ||
| 10-64 | Easement dated as of March 16, 1987 from Ohio Edison Company, Grantor, to The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of March 16, 1987, with Security Pacific Capital Leasing Corporation, Grantee. (incorporated by reference to 1986 Form 10-K, Exhibit 28-23) | ||
| 10-65 | Refinancing Agreement dated as of November 1, 1991 among Perry One Alpha Limited Partnership, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York, as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-82) | ||
| 10-66 | Refinancing Agreement dated as of November 1, 1991 among Security Pacific Leasing Corporation, as Owner Participant, PNPP Funding Corporation, as Funding Corporation, PNPP II Funding Corporation, as New Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee, The Bank of New York, as Collateral Trust Trustee, The Bank of New York as New Collateral Trust Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1991 Form 10-K, Exhibit 10-83) | ||
| 10-67 | Ohio Edison Company Master Decommissioning Trust Agreement for Perry Nuclear Power Plant Unit One, Perry Nuclear Power Plant Unit Two, Beaver Valley Power Station Unit One and Beaver Valley Power Station Unit Two dated July 1, 1993. (1993 Form 10-K, Exhibit 10-94) | ||
| (D) 10-68 | Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-1) | ||
| (D) 10-69 | Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-2) | ||
| (D) 10-70 | Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-99) | ||
| (D) 10-71 | Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-100) | ||
| (D) 10-72 | Amendment No. 5 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Beaver Valley Two Pi Limited Partnership, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-118, File No. 001-02578) | ||
| (D) 10-73 | Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-3) |
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| (D) 10-74 | Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-4) | ||
| (D) 10-75 | Amendment No. 2 dated as of November 5, 1992, to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-103) | ||
| (D) 10-76 | Amendment No. 3 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Beaver Valley Two Pi Limited Partnership, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-122, File No. 001-02578) | ||
| (D) 10-77 | Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, Tenant. (incorporated by reference to 1987 Form 10-K, Exhibit 28-5) | ||
| (D) 10-78 | Trust Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Limited Partnership, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1987 Form 10-K, Exhibit 28-6) | ||
| (D) 10-79 | Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-7) | ||
| (D) 10-80 | Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Beaver Valley Two Pi Limited Partnership and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-8) | ||
| (D) 10-81 | Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-9) | ||
| (D) 10-82 | Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-128, File No. 001-02578) | ||
| (D) 10-83 | Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Beaver Valley Two Pi Inc. and PARock Limited Partnership as General Partners and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-129, File No. 001-02578) | ||
| (D) 10-84 | Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (1987 Form 10-K, Exhibit 28-10) | ||
| (D) 10-85 | Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-131, File No. 001-02578) | ||
| (D) 10-86 | Amendment No. 2 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between HG Power Plant, Inc., as Limited Partner and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-132, File No. 001-02578) |
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| (D) 10-87 | Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company and Toledo Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-11) | ||
| (D) 10-88 | Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Beaver Valley Two Pi Limited Partnership, and Ohio Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-12) | ||
| (E) 10-89 | Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-13) | ||
| (E) 10-90 | Amendment No. 1 dated as of February 1, 1988, to Participation Agreement dated as of September 15, 1987, among Chrysler Consortium Corporation, as Owner Participant, the Original Loan Participants listed in Schedule 1 Thereto, as Original Loan Participants, BVPS Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-14) | ||
| (E) 10-91 | Amendment No. 3 dated as of March 16, 1988 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-114) | ||
| (E) 10-92 | Amendment No. 4 dated as of November 5, 1992 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-115) | ||
| (E) 10-93 | Amendment No. 5 dated as of January 12, 1993 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-139, File No. 001-02578) | ||
| (E) 10-94 | Amendment No. 6 dated as of September 30, 1994 to Participation Agreement dated as of September 15, 1987, as amended, among Chrysler Consortium Corporation, as Owner Participant, BVPS Funding Corporation, BVPS II Funding Corporation, The First National Bank of Boston, as Owner Trustee, The Bank of New York, as Indenture Trustee and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-140, File No. 001-02578) | ||
| (E) 10-95 | Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, as Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-15) | ||
| (E) 10-96 | Amendment No. 1 dated as of February 1, 1988, to Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, Lessor, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-16) |
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| (E) 10-97 | Amendment No. 2 dated as of November 5, 1992 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-118) | ||
| (E) 10-98 | Amendment No. 3 dated as of January 12, 1993 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to 1992 Form 10-K, Exhibit 10-119) | ||
| (E) 10-99 | Amendment No. 4 dated as of September 30, 1994 to Facility Lease dated as of September 15, 1987, as amended, between The First National Bank of Boston, as Owner Trustee, with Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-145, File No. 001-02578) | ||
| (E) 10-100 | Ground Lease and Easement Agreement dated as of September 15, 1987, between Ohio Edison Company, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, Tenant. (incorporated by reference to 1987 Form 10-K, Exhibit 28-17) | ||
| (E) 10-101 | Trust Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and The First National Bank of Boston. (incorporated by reference to 1987 Form 10-K, Exhibit 28-18) | ||
| (E) 10-102 | Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-19) | ||
| (E) 10-103 | Supplemental Indenture No. 1 dated as of February 1, 1988 to Trust Indenture, Mortgage, Security Agreement and Assignment of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with Chrysler Consortium Corporation and Irving Trust Company, as Indenture Trustee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-20) | ||
| (E) 10-104 | Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, Lessee. (incorporated by reference to 1987 Form 10-K, Exhibit 28-21) | ||
| (E) 10-105 | Amendment No. 1 dated as of November 5, 1992 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-151, File No. 001-02578) | ||
| (E) 10-106 | Amendment No. 2 dated as of January 12, 1993 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-152, File No. 001-02578) | ||
| (E) 10-107 | Amendment No. 3 dated as of September 30, 1994 to Tax Indemnification Agreement dated as of September 15, 1987, between Chrysler Consortium Corporation, as Owner Participant, and Ohio Edison Company, as Lessee. (incorporated by reference to OE’s Form 10-K filed March 21, 1995, Exhibit 10-153, File No. 001-02578) | ||
| (E) 10-108 | Assignment, Assumption and Further Agreement dated as of September 15, 1987, among The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, and Toledo Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-22) |
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| (E) 10-109 | Additional Support Agreement dated as of September 15, 1987, between The First National Bank of Boston, as Owner Trustee under a Trust Agreement, dated as of September 15, 1987, with Chrysler Consortium Corporation, and Ohio Edison Company. (incorporated by reference to 1987 Form 10-K, Exhibit 28-23) | ||
| 10-110 | Operating Agreement for Bruce Mansfield Units Nos. 1, 2 and 3 dated as of June 1, 1976, and executed on September 15, 1987, by and between the CAPCO Companies. (incorporated by reference to 1987 Form 10-K, Exhibit 28-25) | ||
| 10-111 | OE Nuclear Capital Contribution Agreement by and between Ohio Edison Company and FirstEnergy Nuclear Generation Corp. (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-02578) | ||
| 10-112 | OE Fossil Purchase and Sale Agreement by and between Ohio Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to OE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-02578) | ||
| 10-113 | OE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and Ohio Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.18, File No. 333-145140-01) | ||
| 10-114 | Consent Decree dated March 18, 2005. (incorporated by reference to FE’s Form 8-K filed March 18, 2005, Exhibit 10.1, File No. 333-21011) | ||
| 10-115 | Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to OE’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-02578) | ||
| 10-118 | Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to OE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 001-02578) | ||
| (A) 12-3 | Consolidated ratios of earnings to fixed charges. | ||
| (A) 23-2 | Consent of Independent Registered Public Accounting Firm. | ||
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | ||
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | ||
| (A) | Provided herein in electronic format as an exhibit. | ||
| (B) | Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K. | ||
| (C) | Substantially similar documents have been entered into relating to three additional Owner Participants. | ||
| (D) | Substantially similar documents have been entered into relating to five additional Owner Participants. | ||
| (E) | Substantially similar documents have been entered into relating to two additional Owner Participants. |
3. Exhibits — Common Exhibits for CEI and TE
| Exhibit | |||
| Number | |||
| 2-1 | Agreement and Plan of Merger between Ohio Edison Company and Centerior Energy dated as of September 13, 1996. (incorporated by reference to FE’s Form S-4 filed February 3, 1997, Exhibit (2)-1, File No. 333-21011) | ||
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| Exhibit | |||
| Number | |||
| 2-2 | Merger Agreement by and among Centerior Acquisition Corp., FirstEnergy Corp and Centerior Energy Corp. (incorporated by reference to FE’s Form S-4 filed February 3, 1997, Exhibit (2)-3, File No. 333-21011) | ||
| 10-1 | CAPCO Administration Agreement dated November 1, 1971, as of September 14, 1967, among the CAPCO Group members regarding the organization and procedures for implementing the objectives of the CAPCO Group. (incorporated by reference to Amendment No. 1, Exhibit 5(p), File No. 2-42230) | ||
| 10-2 | Amendment No. 1, dated January 4, 1974, to CAPCO Administration Agreement among the CAPCO Group members. (incorporated by reference to OE’s File No. 2-68906, Exhibit 5(c)(3)) | ||
| 10-3 | Agreement for the Termination or Construction of Certain Agreement By and Among the CAPCO Group members, dated December 23, 1993 and effective as of September 1, 1980. (incorporated by reference to CEI’s Form 10-K filed on March 31, 1994, Exhibit 10b(4), File No. 001-02323) | ||
| 10-4 | Second Amendment to the Bruce Mansfield Units 1, 2, and 3 Operating Agreement, dated as of July 1, 2007, between FirstEnergy Generation Corp., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FE’s Form 8-K/A filed August 2, 2007, Exhibit 10-11, File. No. 333-21011) | ||
| 10-5 | Amendment No. 6A dated as of December 1, 1991, to the Bond Guaranty dated as of October 1, 1973, by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to OE’s 1991 Form 10-K , Exhibit 10-33) | ||
| 10-6 | Amendment No. 6B dated as of December 30, 1991, to the Bond Guaranty dated as of October 1, 1973 by The Cleveland Electric Illuminating Company, Duquesne Light Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company to National City Bank, as Bond Trustee. (incorporated by reference to OE’s 1991 Form 10-K, Exhibit 10-34) | ||
| 10-7 | Form of Collateral Trust Indenture among CTC Beaver Valley Funding Corporation, The Cleveland Electric Illuminating Company, The Toledo Edison Company and Irving Trust Company, as Trustee. (incorporated by reference to File No. 33-18755, Exhibit 4(a)) | ||
| 10-8 | Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-10 above, including form of Secured Lease Obligation bond. (incorporated by reference to File No. 33-18755, Exhibit 4(b)) | ||
| 10-9 | Form of Collateral Trust Indenture among Beaver Valley II Funding Corporation, The Cleveland Electric Illuminating Company and The Toledo Edison Company and The Bank of New York, as Trustee. (incorporated by reference to File No. 33-46665, Exhibit (4)(a)) | ||
| 10-10 | Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-12 above, including form of Secured Lease Obligation Bond. (incorporated by reference to File No. 33-46665, Exhibit (4)(b)) | ||
| 10-11 | Form of Collateral Trust Indenture among CTC Mansfield Funding Corporation, Cleveland Electric, Toledo Edison and IBJ Schroder Bank & Trust Company, as Trustee. (incorporated by reference to File No. 33-20128, Exhibit 4(a)) | ||
| 10-12 | Form of Supplemental Indenture to Collateral Trust Indenture constituting Exhibit 10-14 above, including forms of Secured Lease Obligation bonds. (incorporated by reference to File No. 33-20128, Exhibit 4(b)) | ||
| 10-13 | Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the limited partnership Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessee. (incorporated by reference to File No. 33-18755, Exhibit 4(c)) | ||
| 10-14 | Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-16 above. (incorporated by reference to File No. 33-18755, Exhibit 4(e)) | ||
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| Exhibit | ||
| Number | ||
| 10-15 | Form of Facility Lease dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the corporate Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (incorporated by reference to File No. 33-18755, Exhibit 4(d)) | |
| 10-16 | Form of Amendment No. 1 to Facility Lease constituting Exhibit 10-18 above. (incorporated by reference to File No. 33-18755, Exhibit 4(f)) | |
| 10-17 | Form of Facility Lease dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Lessor, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, Lessees. (incorporated by reference to File No. 33-20128, Exhibit 4(c)) | |
| 10-18 | Form of Amendment No. 1 to the Facility Lease constituting Exhibit 10-20 above. (incorporated by reference to File No. 33-20128, Exhibit 4(f)) | |
| 10-19 | Form of Participation Agreement dated as of September 15, 1987 among the limited partnership Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Original Loan Participants, CTC Beaver Valley Fund Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-18755, Exhibit 28(a)) | |
| 10-20 | Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-22 above (incorporated by reference to File No. 33-18755, Exhibit 28(c)) | |
| 10-21 | Form of Participation Agreement dated as of September 15, 1987 among the corporate Owner Participant named therein, the Original Loan Participants listed in Schedule 1 thereto, as Owner Loan Participants, CTC Beaver Valley Funding Corporation, as Funding Corporation, The First National Bank of Boston, as Owner Trustee, Irving Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-18755, Exhibit 28(b)) | |
| 10-22 | Form of Amendment No. 1 to Participation Agreement constituting Exhibit 10-24 above (incorporated by reference to File No. 33-18755, Exhibit 28(d)) | |
| 10-23 | Form of Participation Agreement dated as of September 30, 1987 among the Owner Participant named therein, the Original Loan Participants listed in Schedule II thereto, as Owner Loan Participants, CTC Mansfield Funding Corporation, Meridian Trust Company, as Owner Trustee, IBJ Schroder Bank & Trust Company, as Indenture Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-0128, Exhibit 28(a)) | |
| 10-24 | Form of Amendment No. 1 to the Participation Agreement constituting Exhibit 10-26 above (incorporated by reference to File No. 33-20128, Exhibit 28(b)) | |
| 10-25 | Form of Ground Lease dated as of September 15, 1987 between Toledo Edison, Ground Lessor, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-18755, Exhibit 28(e)) | |
| 10-26 | Form of Site Lease dated as of September 30, 1987 between Toledo Edison, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-20128, Exhibit 28(c)) | |
| 10-27 | Form of Site Lease dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Lessor, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Tenant. (incorporated by reference to File No. 33-20128, Exhibit 28(d)) | |
| 10-28 | Form of Amendment No. 1 to the Site Leases constituting Exhibits 10-29 and 10-30 above (incorporated by reference to File No. 33-20128, Exhibit 4(f)) |
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| Exhibit | ||
| Number | ||
| 10-29 | Form of Assignment, Assumption and Further Agreement dated as of September 15, 1987 among The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company, Pennsylvania Power Company and The Toledo Edison Company. (incorporated by reference to File No. 33-18755, Exhibit 28(f)) | |
| 10-30 | Form of Additional Support Agreement dated as of September 15, 1987 between The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein and The Toledo Edison Company. (incorporated by reference to File No. 33-18755, Exhibit 28(g)) | |
| 10-31 | Form of Support Agreement dated as of September 30, 1987 between Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, The Toledo Edison Company, The Cleveland Electric Illuminating Company, Duquesne, Ohio Edison Company and Pennsylvania Power Company. (incorporated by reference to File No. 33-20128, Exhibit 28(e)) | |
| 10-32 | Form of Indenture, Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and The First National Bank of Boston, as Owner Trustee under a Trust Agreement dated as of September 15, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-18755, Exhibit 28(h)) | |
| 10-33 | Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Toledo Edison Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-20128, Exhibit 28(f)) | |
| 10-34 | Form of Bill of Sale, Instrument of Transfer and Severance Agreement dated as of September 30, 1987 between The Cleveland Electric Illuminating Company, Seller, and Meridian Trust Company, as Owner Trustee under a Trust Agreement dated as of September 30, 1987 with the Owner Participant named therein, Buyer. (incorporated by reference to File No. 33-20128, Exhibit 28(g)) | |
| 10-35 | Forms of Refinancing Agreement, including exhibits thereto, among the Owner Participant named therein, as Owner Participant, CTC Beaver Valley Funding Corporation, as Funding Corporation, Beaver Valley II Funding Corporation, as New Funding Corporation, The Bank of New York, as Indenture Trustee, The Bank of New York, as New Collateral Trust Trustee, and The Cleveland Electric Illuminating Company and The Toledo Edison Company, as Lessees. (incorporated by reference to File No. 33-46665, Exhibit (28)(e)(i)) | |
| 10-36 | Form of Amendment No. 2 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(a), File No. 333-47651) | |
| 10-37 | Form of Amendment No. 3 to Facility Lease among Citicorp Lescaman, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(b), File No. 333-47651) | |
| 10-38 | Form of Amendment No. 2 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(c), File No. 333-47651) | |
| 10-39 | Form of Amendment No. 3 to Facility Lease among US West Financial Services, Inc., The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 10(d), File No. 333-47651) | |
| 10-40 | Form of Amendment No. 2 to Facility Lease among Midwest Power Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998 , Exhibit 10(e), File No. 333-47651) | |
| 10-41 | Centerior Energy Corporation Equity Compensation Plan. (incorporated by reference to Centerior Energy Corporation’s Form S-8 filed May 26, 1995, Exhibit 99, File No. 33-59635) |
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| Exhibit | ||
| Number | ||
| 10-42 | Revised Power Supply Agreement, dated December 8, 2006, among FirstEnergy Solutions Corp., Ohio Edison Company, The Cleveland Electric Illuminating Company and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.34, File No. 333-145140-01) |
3. Exhibits — CEI
| 3-1 | Amended and Restated Articles of Incorporation of The Cleveland Electric Illuminating Company, Effective December 21, 2007. (incorporated by reference to CEI’s Form 10-K filed February 29, 2008, Exhibit 3.3, File No. 001-02323) | |
| 3-2 | Amended and Restated Code of Regulations of The Cleveland Electric Illuminating Company, dated December 14, 2007. (incorporated by reference to CEI’s Form 10-K filed February 29, 2008, Exhibit 3.4, File No. 001-02323) | |
| (B) 4-1 | Mortgage and Deed of Trust between The Cleveland Electric Illuminating Company and Guaranty Trust Company of New York (now The Chase Manhattan Bank (National Association)), as Trustee, dated July 1, 1940. (incorporated by reference to File No. 2-4450, Exhibit 7(a)) | |
| Supplemental Indentures between The Cleveland Electric Illuminating Company and the Trustee, supplemental to Exhibit 4-1, dated as follows: | ||
| 4-1(a) | July 1, 1940 (incorporated by reference to File No. 2-4450, Exhibit 7(b)) | |
| 4-1(b) | August 18, 1944 (incorporated by reference to File No. 2-9887, Exhibit 4(c)) | |
| 4-1(c) | December 1, 1947 (incorporated by reference to File No. 2-7306, Exhibit 7(d)) | |
| 4-1(d) | September 1, 1950 (incorporated by reference to File No. 2-8587, Exhibit 7(c)) | |
| 4-1(e) | June 1, 1951 (incorporated by reference to File No. 2-8994, Exhibit 7(f)) | |
| 4-1(f) | May 1, 1954 (incorporated by reference to File No. 2-10830, Exhibit 4(d)) | |
| 4-1(g) | March 1, 1958 (incorporated by reference to File No. 2-13839, Exhibit 2(a)(4)) | |
| 4-1(h) | April 1, 1959 (incorporated by reference to File No. 2-14753, Exhibit 2(a)(4)) | |
| 4-1(i) | December 20, 1967 (incorporated by reference to File No. 2-30759, Exhibit 2(a)(4)) | |
| 4-1(j) | January 15, 1969 (incorporated by reference to File No. 2-30759, Exhibit 2(a)(5)) | |
| 4-1(k) | November 1, 1969 (incorporated by reference to File No. 2-35008, Exhibit 2(a)(4)) | |
| 4-1(l) | June 1, 1970 (incorporated by reference to File No. 2-37235, Exhibit 2(a)(4)) | |
| 4-1(m) | November 15, 1970 (incorporated by reference to File No. 2-38460, Exhibit 2(a)(4)) | |
| 4-1(n) | May 1, 1974 (incorporated by reference to File No. 2-50537, Exhibit 2(a)(4)) | |
| 4-1(o) | April 15, 1975 (incorporated by reference to File No. 2-52995, Exhibit 2(a)(4)) | |
| 4-1(p) | April 16, 1975 (incorporated by reference to File No. 2-53309, Exhibit 2(a)(4)) | |
| 4-1(q) | May 28, 1975 (incorporated by reference to Form 8-A filed June 5, 1975, Exhibit 2(c), File No. 1-2323) | |
| 4-1(r) | February 1, 1976 (incorporated by reference to 1975 Form 10-K, Exhibit 3(d)(6), File No. 1-2323) | |
| 4-1(s) | November 23, 1976 (incorporated by reference to File No. 2-57375, Exhibit 2(a)(4)) | |
| 4-1(t) | July 26, 1977 (incorporated by reference to File No. 2-59401, Exhibit 2(a)(4)) | |
| 4-1(u) | September 7, 1977 (incorporated by reference to File No. 2-67221, Exhibit 2(a)(5)) | |
| 4-1(v) | May 1, 1978 (incorporated by reference to June 1978 Form 10-Q, Exhibit 2(b), File No. 1-2323) | |
| 4-1(w) | September 1, 1979 (incorporated by reference to September 1979 Form 10-Q, Exhibit 2(a), File No. 1-2323) | |
| 4-1(x) | April 1, 1980 (incorporated by reference to September 1980 Form 10-Q, Exhibit 4(a)(2), File No. 1-2323) | |
| 4-1(y) | April 15, 1980 (incorporated by reference to September 1980 Form 10-Q, Exhibit 4(b), File No. 1-2323) | |
| 4-1(z) | May 28, 1980 (incorporated by reference to Amendment No. 1, Exhibit 2(a)(4), File No. 2-67221) | |
| 4-1(aa) | June 9, 1980 (incorporated by reference to September 1980 Form 10-Q, Exhibit 4(d), File No. 1-2323) | |
| 4-1(bb) | December 1, 1980 (incorporated by reference to 1980 Form 10-K, Exhibit 4(b)(29), File No. 1-2323) | |
| 4-1(cc) | July 28, 1981 (incorporated by reference to September 1981 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(dd) | August 1, 1981 (incorporated by reference to September 1981 Form 10-Q, Exhibit 4(b), File No. 1-2323) | |
| 4-1(ee) | March 1, 1982 (incorporated by reference to Amendment No. 1, Exhibit 4(b)(3), File No. 2-76029) | |
| 4-1(ff) | July 15, 1982 (incorporated by reference to September 1982 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(gg) | September 1, 1982 (incorporated by reference to September 1982 Form 10-Q, Exhibit 4(a)(1), File No. 1-2323) |
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| 4-1(hh) | November 1, 1982 (incorporated by reference to September 1982 Form 10-Q, Exhibit (a)(2), File No. 1-2323) | |
| 4-1(ii) | November 15, 1982 (incorporated by reference to 1982 Form 10-K, Exhibit 4(b)(36), File No. 1-2323) | |
| 4-1(jj) | May 24, 1983 (incorporated by reference to June 1983 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(kk) | May 1, 1984 (incorporated by reference to June 1984 Form 10-Q, Exhibit 4, File No. 1-2323) | |
| 4-1(ll) | May 23, 1984 (incorporated by reference to Form 8-K dated May 22, 1984, Exhibit 4, File No. 1-2323) | |
| 4-1(mm) | June 27, 1984 (incorporated by reference to Form 8-K dated June 11, 1984, Exhibit 4, File No. 1-2323) | |
| 4-1(nn) | September 4, 1984 (incorporated by reference to 1984 Form 10-K, Exhibit 4b(41), File No. 1-2323) | |
| 4-1(oo) | November 14, 1984 (incorporated by reference to 1984 Form 10 K, Exhibit 4b(42), File No. 1-2323) | |
| 4-1(pp) | November 15, 1984 (incorporated by reference to 1984 Form 10-K, Exhibit 4b(43), File No. 1-2323) | |
| 4-1(qq) | April 15, 1985 incorporated by reference to (Form 8-K dated May 8, 1985, Exhibit 4(a), File No. 1-2323) | |
| 4-1(rr) | May 28, 1985 (incorporated by reference to Form 8-K dated May 8, 1985, Exhibit 4(b), File No. 1-2323) | |
| 4-1(ss) | August 1, 1985 (incorporated by reference to September 1985 Form 10-Q, Exhibit 4, File No. 1-2323) | |
| 4-1(tt) | September 1, 1985 (incorporated by reference to Form 8-K dated September 30, 1985, Exhibit 4, File No. 1-2323) | |
| 4-1(uu) | November 1, 1985 (incorporated by reference to Form 8-K dated January 31, 1986, Exhibit 4, File No. 1-2323) | |
| 4-1(vv) | April 15, 1986 (incorporated by reference to March 1986 Form 10-Q, Exhibit 4, File No. 1-2323) | |
| 4-1(ww) | May 14, 1986 (incorporated by reference to June 1986 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(xx) | May 15, 1986 (incorporated by reference to June 1986 Form 10-Q, Exhibit 4(b), File No. 1-2323) | |
| 4-1(yy) | February 25, 1987 (incorporated by reference to 1986 Form 10-K, Exhibit 4b(52), File No. 1-2323) | |
| 4-1(zz) | October 15, 1987 (incorporated by reference to September 1987 Form 10-Q, Exhibit 4, File No. 1-2323) | |
| 4-1(aaa) | February 24, 1988 (incorporated by reference to 1987 Form 10-K, Exhibit 4b(54), File No. 1-2323) | |
| 4-1(bbb) | September 15, 1988 (incorporated by reference to 1988 Form 10-K, Exhibit 4b(55), File No. 1-2323) | |
| 4-1(ccc) | May 15, 1989 (incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(i)) | |
| 4-1(ddd) | June 13, 1989 (incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(ii)) | |
| 4-1(eee) | October 15, 1989 (incorporated by reference to File No. 33-32724, Exhibit 4(a)(2)(iii)) | |
| 4-1(fff) | January 1, 1990 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(59), File No. 1-2323) | |
| 4-1(ggg) | June 1, 1990 (incorporated by reference to September 1990 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(hhh) | August 1, 1990 (incorporated by reference to September 1990 Form 10-Q, Exhibit 4(b), File No. 1-2323) | |
| 4-1(iii) | May 1, 1991 (incorporated by reference to June 1991 Form 10-Q, Exhibit 4(a), File No. 1-2323) | |
| 4-1(jjj) | May 1, 1992 (incorporated by reference to File No. 33-48845, Exhibit 4(a)(3)) | |
| 4-1(kkk) | July 31, 1992 (incorporated by reference to File No. 33-57292, Exhibit 4(a)(3)) | |
| 4-1(lll) | January 1, 1993 (incorporated by reference to 1992 Form 10-K, Exhibit 4b(65), File No. 1-2323) | |
| 4-1(mmm) | February 1, 1993 (incorporated by reference to 1992 Form 10-K, Exhibit 4b(66), File No. 1-2323) | |
| 4-1(nnn) | May 20, 1993 (incorporated by reference to Form 8-K dated July 14, 1993, Exhibit 4(a), File No. 1-2323) | |
| 4-1(ooo) | June 1, 1993 (incorporated by reference to Form 8-K dated July 14, 1993, Exhibit 4(b), File No. 1-2323) | |
| 4-1(ppp) | September 15, 1994 (incorporated by reference to CEI’s Form 10-Q filed November 14, 1994, Exhibit 4(a), File No. 001-02323) | |
| 4-1(qqq) | May 1, 1995 (incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(a), File No. 001-02323) | |
| 4-1(rrr) | May 2, 1995 (incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(b) , File No. 001-02323) | |
| 4-1(sss) | June 1, 1995 (incorporated by reference to CEI’s Form 10-Q filed November 13, 1995, Exhibit 4(c), File No. 001-02323) | |
| 4-1(ttt) | July 15, 1995 (incorporated by reference to CEI’s Form 10-K filed March 29, 1996, Exhibit 4b(73), File No. 001-02323) | |
| 4-1(uuu) | August 1, 1995 (incorporated by reference to CEI’s Form 10-K filed March 29, 1996, Exhibit 4b(74), File No. 001-02323) |
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| 4-1(vvv) | June 15, 1997 (incorporated by reference to CEI’s Form S-4 filed September 18, 2007, Exhibit 4(a), File No. 333-35931) | |
| 4-1(www) | October 15, 1997 (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 4(a), File No. 333-47651) | |
| 4-1(xxx) | June 1, 1998 (incorporated by reference to CEI’s Form S-4, Exhibit 4b(77), File No. 333-72891) | |
| 4-1(yyy) | October 1, 1998 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(78), File No. 333-72891) | |
| 4-1(zzz) | October 1, 1998 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(79), File No. 333-72891) | |
| 4-1(aaaa) | February 24, 1999 (incorporated by reference to CEI’s Form S-4 filed February 24, 1999, Exhibit 4b(80), File No. 333-72891) | |
| 4-1(bbbb) | September 29, 1999 (incorporated by reference to CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(81), File No. 001-02323) | |
| 4-1(cccc) | January 15, 2000 (incorporated by reference to CEI’s Form 10-K filed March 29, 2000, Exhibit 4b(82), File No. 001-02323) | |
| 4-1(dddd) | May 15, 2002 (incorporated by reference to CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(83), File No. 001-02323) | |
| 4-1(eeee) | October 1, 2002 (incorporated by reference to CEI’s Form 10-K filed March 26, 2003, Exhibit 4b(84), File No. 001-02323) | |
| 4-1(ffff) | Supplemental Indenture dated as of September 1, 2004 (incorporated by reference to CEI’s Form 10-Q filed November 4, 2004, Exhibit 4-1(85), File No. 001-02323) | |
| 4-1(gggg) | Supplemental Indenture dated as of October 1, 2004 (incorporated by reference to CEI’s Form 10-Q filed November 4, 2004, Exhibit 4-1(86), File No. 001-02323) | |
| 4-1(hhhh) | Supplemental Indenture dated as of April 1, 2005 (incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.1, File No. 001-02323) | |
| 4-1(iiii) | Supplemental Indenture dated as of July 1, 2005 (incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 4.2, File No. 001-02323) | |
| 4-1(jjjj) | Eighty-Ninth Supplemental Indenture, dated as of November 1, 2008 (relating to First Mortgage Bonds, 8.875% Series due 2018). (incorporated by reference to CEI’s Form 8-K filed November 19, 2008, Exhibit 4.1, File No. 001-02323) | |
| 4-1(kkk) | Ninetieth Supplemental Indenture, dated as of August 1, 2009 (including Form of First Mortgage Bonds, 5.50% Series due 2024). (incorporated by reference to CEI’s Form 8-K filed on August 18, 2009, Exhibit 4.1, File No. 001-02323) | |
| 4-2 | Form of Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 4(b), File No. 333-47651) | |
| 4-2(a) | Form of Supplemental Note Indenture between The Cleveland Electric Illuminating Company and The Chase Manhattan Bank, as Trustee dated as of October 24, 1997. (incorporated by reference to CEI’s Form S-4 filed March 10, 1998, Exhibit 4(c), File No. 333-47651) | |
| 4-3 | Indenture dated as of December 1, 2003 between The Cleveland Electric Illuminating Company and JPMorgan Chase Bank, as Trustee. (incorporated by reference to CEI’s Form 10-K filed March 15, 2004, Exhibit 4-1, File No. 001-02323) | |
| 4-3(a) | Officer’s Certificate (including the form of 5.95% Senior Notes due 2036), dated as of December 11, 2006. (incorporated by reference to CEI’s Form 8-K filed December 12, 2006, Exhibit 4, File No. 001-02323) | |
| 4-3(b) | Officer’s Certificate (including the form of 5.70% Senior Notes due 2017), dated as of March 27, 2007. (incorporated by reference to CEI’s Form 8-K filed March 28, 2007, Exhibit 4, File No. 001-02323) | |
| 10-1 | CEI Nuclear Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company and FirstEnergy Nuclear Generation Corp. (incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-02323) | |
| 10-2 | CEI Fossil Purchase and Sale Agreement by and between The Cleveland Electric Illuminating Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to CEI’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-02323) | |
| 10-3 | CEI Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Cleveland Electric Illuminating Company. (Form S-4/A filed August 20, 2007, Exhibit 10.16, File No. 333-145140-01) |
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| 10-4 | CEI Nuclear Security Agreement, dated December 16, 2005, by and between FirstEnergy Nuclear Generation Corp. and The Cleveland Electric Illuminating Company. (incorporated by reference to FE’s Form S-4/A filed August 20, 2007, Exhibit 10.26, File No. 333-145140-01) | |
| 10-5 | Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to CEI’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-02323) | |
| 10-7 | Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to CEI’s Form 10-K filed March 2, 2006, Exhibit 10-65, File No. 001-02323) | |
| 10-8 | Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to CEI’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 001-02323) | |
| (A) 12-4 | Consolidated ratios of earnings to fixed charges. | |
| (A) 23-3 | Consent of Independent Registered Public Accounting Firm. | |
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | |
| (A) | Provided herein in electronic format as an exhibit. | |
| (B) | Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, CEI has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of CEI, but hereby agrees to furnish to the Commission on request any such instruments. | |
3. Exhibits — TE
| 3-1 | Amended and Restated Articles of Incorporation of The Toledo Edison Company, effective December 18, 2007. (incorporated by reference to TE’s Form 10-K filed February 29, 2008, Exhibit 3c, File No. 001-03583) | |
| 3-2 | Amended and Restated Code of Regulations of The Toledo Edison Company, dated December 14, 2007. (incorporated by reference to TE’s Form 10-K filed February 29, 2008, Exhibit 3d, File No. 001-03583) | |
| (B) 4-1 | Indenture, dated as of April 1, 1947, between The Toledo Edison Company and The Chase National Bank of the City of New York (now The Chase Manhattan Bank (National Association)), as Trustee. (incorporated by reference to File No. 2-26908, Exhibit 2(b)) | |
| Supplemental Indentures between The Toledo Edison Company and the Trustee, supplemental to Exhibit 4-1, dated as follows: | ||
| 4-1(a) | September 1, 1948 (incorporated by reference to File No. 2-26908, Exhibit 2(d)) | |
| 4-1(b) | April 1, 1949 (incorporated by reference to File No. 2-26908, Exhibit 2(e)) | |
| 4-1(c) | December 1, 1950 (incorporated by reference to File No. 2-26908, Exhibit 2(f)) | |
| 4-1(d) | March 1, 1954 (incorporated by reference to File No. 2-26908, Exhibit 2(g)) | |
| 4-1(e) | February 1, 1956 (incorporated by reference to File No. 2-26908, Exhibit 2(h)) | |
| 4-1(f) | May 1, 1958 (incorporated by reference to File No. 2-59794, Exhibit 5(g)) | |
| 4-1(g) | August 1, 1967 (incorporated by reference to File No. 2-26908, Exhibit 2(c)) | |
| 4-1(h) | November 1, 1970 (incorporated by reference to File No. 2-38569, Exhibit 2(c)) | |
| 4-1(i) | August 1, 1972 (incorporated by reference to File No. 2-44873, Exhibit 2(c)) | |
| 4-1(j) | November 1, 1973 (incorporated by reference to File No. 2-49428, Exhibit 2(c)) | |
| 4-1(k) | July 1, 1974 (incorporated by reference to File No. 2-51429, Exhibit 2(c)) | |
| 4-1(l) | October 1, 1975 (incorporated by reference to File No. 2-54627, Exhibit 2(c)) | |
| 4-1(m) | June 1, 1976 (incorporated by reference to File No. 2-56396, Exhibit 2(c)) |
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| 4-1(n) | October 1, 1978 (incorporated by reference to File No. 2-62568, Exhibit 2(c)) | |
| 4-1(o) | September 1, 1979 (incorporated by reference to File No. 2-65350, Exhibit 2(c)) | |
| 4-1(p) | September 1, 1980 (incorporated by reference to File No. 2-69190, Exhibit 4(s)) | |
| 4-1(q) | October 1, 1980 (incorporated by reference to File No. 2-69190, Exhibit 4(c)) | |
| 4-1(r) | April 1, 1981 (incorporated by reference to File No. 2-71580, Exhibit 4(c)) | |
| 4-1(s) | November 1, 1981 (incorporated by reference to File No. 2-74485, Exhibit 4(c)) | |
| 4-1(t) | June 1, 1982 (incorporated by reference to File No. 2-77763, Exhibit 4(c)) | |
| 4-1(u) | September 1, 1982 (incorporated by reference to File No. 2-87323, Exhibit 4(x)) | |
| 4-1(v) | April 1, 1983 (incorporated by reference to March 1983 Form 10-Q, Exhibit 4(c), File No. 1-3583) | |
| 4-1(w) | December 1, 1983 (incorporated by reference to 1983 Form 10-K, Exhibit 4(x), File No. 1-3583) | |
| 4-1(x) | April 1, 1984 (incorporated by reference to File No. 2-90059, Exhibit 4(c)) | |
| 4-1(y) | October 15, 1984 (incorporated by reference to 1984 Form 10-K, Exhibit 4(z), File No. 1-3583) | |
| 4-1(z) | October 15, 1984 (incorporated by reference to 1984 Form 10-K, Exhibit 4(aa), File No. 1-3583) | |
| 4-1(aa) | August 1, 1985 (incorporated by reference to File No. 33-1689, Exhibit 4(dd)) | |
| 4-1(bb) | August 1, 1985 (incorporated by reference to File No. 33-1689, Exhibit 4(ee)) | |
| 4-1(cc) | December 1, 1985 (incorporated by reference to File No. 33-1689, Exhibit 4(c)) | |
| 4-1(dd) | March 1, 1986 (incorporated by reference to 1986 Form 10-K, Exhibit 4b(31), File No. 1-3583) | |
| 4-1(ee) | October 15, 1987 (incorporated by reference to September 30, 1987 Form 10-Q, Exhibit 4, File No. 1-3583) | |
| 4-1(ff) | September 15, 1988 (incorporated by reference to 1988 Form 10-K, Exhibit 4b(33), File No. 1-3583) | |
| 4-1(gg) | June 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(34), File No. 1-3583) | |
| 4-1(hh) | October 15, 1989 (incorporated by reference to 1989 Form 10-K, Exhibit 4b(35), File No. 1-3583) | |
| 4-1(ii) | May 15, 1990 (incorporated by reference to June 30, 1990 Form 10-Q, Exhibit 4, File No. 1-3583) | |
| 4-1(jj) | March 1, 1991 (incorporated by reference to June 30, 1991 Form 10-Q, Exhibit 4(b), File No. 1-3583) | |
| 4-1(kk) | May 1, 1992 (incorporated by reference to File No. 33-48844, Exhibit 4(a)(3)) | |
| 4-1(ll) | August 1, 1992 (incorporated by reference to 1992 Form 10-K, Exhibit 4b(39), File No. 1-3583) | |
| 4-1(mm) | October 1, 1992 (incorporated by reference to 1992 Form 10-K, Exhibit 4b(40), File No. 1-3583) | |
| 4-1(nn) | January 1, 1993 (incorporated by reference to 1992 Form 10-K, Exhibit 4b(41), File No. 1-3583) | |
| 4-1(oo) | September 15, 1994 (incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(b), File No. 001-03583) | |
| 4-1(pp) | May 1, 1995 (incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(d), File No. 001-03583) | |
| 4-1(qq) | June 1, 1995 (incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(e), File No. 001-03583) | |
| 4-1(rr) | July 14, 1995 (incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(f), File No. 001-03583) | |
| 4-1(ss) | July 15, 1995 (incorporated by reference to TE’s Form 10-Q filed November 14, 1994, Exhibit 4(g), File No. 1-3583) | |
| 4-1(tt) | August 1, 1997 (incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(47), File No. 001-03583) | |
| 4-1(uu) | June 1, 1998 (incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(48), File No. 001-03583) | |
| 4-1(vv) | January 15, 2000 (incorporated by reference to TE’s Form 10-K filed March 29, 1999, Exhibit 4b(49), File No. 001-03583) | |
| 4-1(ww) | May 1, 2000 (incorporated by reference to TE’s Form 10-K filed April 16, 2000, Exhibit 4b(50), File No. 001-03583) | |
| 4-1(xx) | September 1, 2000 (incorporated by reference to TE’s Form 10-K filed April 16, 2001, Exhibit 4b(51), File No. 001-03583) | |
| 4-1(yy) | October 1, 2002 (incorporated by reference to TE’s Form 10-K filed March 26, 2003, Exhibit 4b(52), File No. 001-03583) | |
| 4-1(zz) | April 1, 2003 (incorporated by reference to TE’s Form 10-K filed March 15, 2004, Exhibit 4b(53), File No. 001-03583) | |
| 4-1(aaa) | September 1, 2004 (incorporated by reference to TE’s 10-Q filed November 4, 2004, Exhibit 4.2.56, File No. 001-03583) | |
| 4-1(bbb) | April 1, 2005 (incorporated by reference to TE’s June 2005 10-Q, Exhibit 4.1, File No. 001-03583) | |
| 4-1(ccc) | April 23, 2009 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.3, File No. 001-03583) | |
| 4-1(ddd) | April 24, 2009 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.4, File No. 001-03583) |
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| 4-2 | Indenture dated as of November 1, 2006, between The Toledo Edison Company and The Bank of New York Trust Company, N.A. (incorporated by reference to TE’s Form 10-K filed February 28, 2007, Exhibit 4-2, File No. 001-03583) | |
| 4-2(a) | Officer’s Certificate (including the form of 6.15% Senior Notes due 2037), dated November 16, 2006. (incorporated by reference to TE’s Form 8-K filed November 17, 2006, Exhibit 4, File No. 001-03583) | |
| 4-2(b) | First Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of November 1, 2006 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.1, File No. 001-03583) | |
| 4-2(c) | Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to TE’s Form 8-K filed April 24, 2009, Exhibit 4.2, File No. 001-03583) | |
| 10-1 | TE Nuclear Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Nuclear Generation Corp. (Purchaser). (incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit 10.1, File No. 001-03583) | |
| 10-2 | TE Fossil Purchase and Sale Agreement by and between The Toledo Edison Company (Seller) and FirstEnergy Generation Corp. (Purchaser). (incorporated by reference to TE’s Form 10-Q filed August 1, 2005, Exhibit 10.2, File No. 001-03583) | |
| 10-3 | TE Fossil Security Agreement, dated October 24, 2005, by and between FirstEnergy Generation Corp. and The Toledo Edison Company. (incorporated by reference to FES’ Form S-4/A filed August 20, 2007, Exhibit 10.24, File No. 333-145140-01) | |
| 10-4 | Nuclear Sale/Leaseback Power Supply Agreement dated as of October 14, 2005 between Ohio Edison Company and The Toledo Edison Company (Sellers) and FirstEnergy Nuclear Generation Corp. (Buyer). (incorporated by reference to TE’s Form 10-K filed March 2, 2006, Exhibit 10-64, File No. 001-03583) | |
| 10-6 | Mansfield Power Supply Agreement dated as of October 14, 2005 between The Cleveland Electric Illuminating Company and The Toledo Edison Company (Sellers) and FirstEnergy Generation Corp. (Buyer). (incorporated by reference to TE’s Form 10-K, Exhibit 10-65, File No. 001-03583) | |
| 10-7 | Master SSO Supply Agreement, entered into May 18, 2009, by and between The Cleveland Electric Illuminating Company, the Toledo Edison Company and Ohio Edison Company and FirstEnergy Solutions Corp. (incorporated by reference to TE’s Form 10-Q filed August 3, 2009, Exhibit 10.2, File No. 001-03583 | |
| (A) 12-5 | Consolidated ratios of earnings to fixed charges. | |
| (A) 23-4 | Consent of Independent Registered Public Accounting Firm. | |
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | |
| (A) | Provided herein in electronic format as an exhibit. | |
| (B) | Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, TE has not filed as an exhibit to this Form 10-K any instrument with respect to long-term debt if the total amount of securities authorized thereunder does not exceed 10% of the total assets of TE, but hereby agrees to furnish to the Commission on request any such instruments. |
3. Exhibits — JCP&L
| 3-1 | Amended and Restated Certificate of Incorporation of Jersey Central Power & Light Company, filed February 14, 2008. (incorporated by reference to JCP&L’s Form 10-K filed February 29, 2008, Exhibit 3-D, File No. 001-03141) |
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| 3-2 | Amended and Restated Bylaws of Jersey Central Power & Light Company, dated January 9, 2008. (incorporated by reference to JCP&L’s Form 10-K filed February 29, 2008, Exhibit 3-E, File No. 001-03141) | |
| 4-1 | Senior Note Indenture, dated as of July 1, 1999, between Jersey Central Power & Light Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee to United States Trust Company of New York. (incorporated by reference to JCP&L’s Form S-3 filed May 18, 1999, Exhibit 4-A, File No. 333-78717) | |
| 4-1(a) | First Supplemental Indenture, dated October 31, 2007, between Jersey Central Power & Light Company, The Bank of New York, as resigning trustee, and The Bank of New York Trust Company, N.A., as successor trustee. (incorporated by reference to JCP&L’s Form S-4/A filed November 11, 2007, Exhibit 4-2, File No. 333-146968) | |
| 4-1(b) | Form of Jersey Central Power & Light Company 6.40% Senior Note due 2036. (incorporated by reference to JCP&L’s Form 8-K filed May 12, 2006, Exhibit 10-1, File No. 001-03141) | |
| 4-1(c) | Form of 7.35% Senior Notes due 2019. (incorporated by reference to JCP&L’s Form 8-K filed January 27, 2009, Exhibit 4.1, File No. 001-03141) | |
| 10-1 | Indenture dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 4-1, File No. 001-03141) | |
| 10-2 | 2006-A Series Supplement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and The Bank of New York as Trustee. (incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 4-2) | |
| 10-3 | Bondable Transition Property Sale Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Seller. (incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-1, File No. 001-03141) | |
| 10-4 | Bondable Transition Property Service Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and Jersey Central Power & Light Company as Servicer. (incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-2, File No. 001-03141) | |
| 10-5 | Administration Agreement dated as of August 10, 2006 between JCP&L Transition Funding II LLC as Issuer and FirstEnergy Service Company as Administrator. (incorporated by reference to JCP&L’s Form 8-K filed August 10, 2006, Exhibit 10-3, File No. 001-03141) | |
| (A) 12-6 | Consolidated ratios of earnings to fixed charges. | |
| (A) 23-5 | Consent of Independent Registered Public Accounting Firm. | |
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | |
| (A) | Provided herein electronic format as an exhibit. |
3. Exhibits — Met-Ed
| 3-1 | Amended and Restated Articles of Incorporation of Metropolitan Edison Company, effective December 19, 2007. (incorporated by reference to Met-Ed’s Form 10-K filed February 29, 2008, Exhibit 3.9, File No. 001-00446) | |
| 3-2 | Amended and Restated Bylaws of Metropolitan Edison Company, dated December 14, 2007. (incorporated by reference to Met-Ed’s Form 10-K filed February 29, 2008, Exhibit 3.10, File No. 001-00446) |
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| 4-1 | Indenture of Metropolitan Edison Company, dated November 1, 1944, between Metropolitan Edison Company and United States Trust Company of New York, Successor Trustee, as amended and supplemented by fourteen supplemental indentures dated February 1, 1947 through May 1, 1960. (Metropolitan Edison Company’s Instruments of Indebtedness Nos. 1 to 14 inclusive, and 16, incorporated by reference to Amendment No. 1 to 1959 Annual Report of GPU, Inc. on Form U5S, File Nos. 30-126 and 1-3292) | |
| 4-1(a) | Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1962. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(1)) | |
| 4-1(b) | Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1964. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(2)) | |
| 4-1(c) | Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1965. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(3)) | |
| 4-1(d) | Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1966. (incorporated by reference to Registration No. 2-24883, Exhibit 2-B-4)) | |
| 4-1(e) | Supplemental Indenture of Metropolitan Edison Company, dated March 22, 1968. (incorporated by reference to Registration No. 2-29644, Exhibit 4-C-5) | |
| 4-1(f) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1968. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(6)) | |
| 4-1(g) | Supplemental Indenture of Metropolitan Edison Company, dated August 1, 1969. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(7)) | |
| 4-1(h) | Supplemental Indenture of Metropolitan Edison Company, dated November 1, 1971. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(8)) | |
| 4-1(i) | Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1972. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(9)) | |
| 4-1(j) | Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1973. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(10)) | |
| 4-1(k) | Supplemental Indenture of Metropolitan Edison Company, dated October 30, 1974. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(11)) | |
| 4-1(l) | Supplemental Indenture of Metropolitan Edison Company, dated October 31, 1974. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(12)) | |
| 4-1(m) | Supplemental Indenture of Metropolitan Edison Company, dated March 20, 1975. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(13)) | |
| 4-1(n) | Supplemental Indenture of Metropolitan Edison Company, dated September 25, 1975. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(15)) | |
| 4-1(o) | Supplemental Indenture of Metropolitan Edison Company, dated January 12, 1976. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(16)) | |
| 4-1(p) | Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1976. (incorporated by reference to Registration No. 2-59678, Exhibit 2-E(17)) | |
| 4-1(q) | Supplemental Indenture of Metropolitan Edison Company, dated September 28, 1977. (incorporated by reference to Registration No. 2-62212, Exhibit 2-E(18)) | |
| 4-1(r) | Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1978. (incorporated by reference to Registration No. 2-62212, Exhibit 2-E(19)) | |
| 4-1(s) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1978. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(19)) | |
| 4-1(t) | Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1979. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(20)) | |
| 4-1(u) | Supplemental Indenture of Metropolitan Edison Company, dated January 1, 1980. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(21)) | |
| 4-1(v) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1981. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(22)) | |
| 4-1(w) | Supplemental Indenture of Metropolitan Edison Company, dated September 10, 1981. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(23)) | |
| 4-1(x) | Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1982. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(24)) | |
| 4-1(y) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1983. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(25)) | |
| 4-1(z) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1984. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(26)) | |
| 4-1(aa) | Supplemental Indenture of Metropolitan Edison Company, dated March 1, 1985. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(27)) | |
| 4-1(bb) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1985. (Registration No. 33-48937, Exhibit 4-A(28)) | |
| 4-1(cc) | Supplemental Indenture of Metropolitan Edison Company, dated June 1, 1988. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(29)) | |
| 4-1(dd) | Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (incorporated by |
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| reference to Registration No. 33-48937, Exhibit 4-A(30)) | ||
| 4-1(ee) | Amendment dated May 22, 1990 to Supplemental Indenture of Metropolitan Edison Company, dated April 1, 1990. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(31)) | |
| 4-1(ff) | Supplemental Indenture of Metropolitan Edison Company, dated September 1, 1992. (incorporated by reference to Registration No. 33-48937, Exhibit 4-A(32)(a)) | |
| 4-1(gg) | Supplemental Indenture of Metropolitan Edison Company, dated December 1, 1993. (incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 1994, Exhibit C-58, File No. 30-126) | |
| 4-1(hh) | Supplemental Indenture of Metropolitan Edison Company, dated July 15, 1995. (incorporated by reference to 1995 Form 10-K, Exhibit 4-B-35, File No. 1-446) | |
| 4-1(ii) | Supplemental Indenture of Metropolitan Edison Company, dated August 15, 1996. (incorporated by reference to Met-Ed’s Form 10-K filed March 10, 1997, Exhibit 4-B-35, File No. 033-51001) | |
| 4-1(jj) | Supplemental Indenture of Metropolitan Edison Company, dated May 1, 1997. (incorporated by reference to Met-Ed’s Form 10-K filed March 13, 1998, Exhibit 4-B-36, File No. 033-51001) | |
| 4-1(kk) | Supplemental Indenture of Metropolitan Edison Company, dated July 1, 1999. (incorporated by reference to Met-Ed’s Form 10-K filed March 20, 2000, Exhibit 4-B-38, File No. 033-51001) | |
| 4-1(ll) | Supplemental Indenture of Metropolitan Edison Company, dated May 1, 2001. (incorporated by reference to Met-Ed’s Form 10-K filed April 1, 2002, Exhibit 4-5, File No. 033-51001) | |
| 4-1(mm) | Supplemental Indenture of Metropolitan Edison Company, dated March 1, 2003. (incorporated by reference to Met-Ed’s Form 10-K filed March 15, 2004, Exhibit 4-10, File No. 033-51001) | |
| 4-2 | Senior Note Indenture between Metropolitan Edison Company and United States Trust Company of New York, dated July 1, 1999. (incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 2002, Exhibit C-154, File No. 001-06047) | |
| 4-2(a) | Form of Metropolitan Edison Company 7.70% Senior Notes due 2019. (incorporated by reference to Met-Ed’s Form 8-K filed January 21, 2009, Exhibit 4.1, File No. 001-00446) | |
| (A) 12-7 | Consolidated ratios of earnings to fixed charges. | |
| (A) 23-6 | Consent of Independent Registered Public Accounting Firm. | |
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | |
| (A) | Provided herein electronic format as an exhibit. | |
3. Exhibits — Penelec
| 3-1 | Amended and Restated Articles of Incorporation of Pennsylvania Electric Company, effective December 19, 2007. (incorporated by reference to Penelec’s Form 10-K filed February 29, 2008, Exhibit 3.11, File No. 001-03522) | |
| 3-2 | Amended and Restated Bylaws of Pennsylvania Electric Company, dated December 14, 2007. (incorporated by reference to Penelec’s Form 10-K filed February 29, 2008, Exhibit 3.12, File No. 001-03522) | |
| 4-1 | Mortgage and Deed of Trust of Pennsylvania Electric Company, dated January 1, 1942, between Pennsylvania Electric Company and United States Trust Company of New York, Successor Trustee, and indentures supplemental thereto dated March 7, 1942 through May 1, 1960 — (Pennsylvania Electric Company’s Instruments of Indebtedness Nos. 1-20, inclusive, incorporated by reference to Amendment No. 1 to 1959 Annual Report of GPU on Form U5S, File Nos. 30-126 and 1-3292) | |
| 4-1(a) | Supplemental Indentures to Mortgage and Deed of Trust of Pennsylvania Electric Company, dated May 1, 1961 through December 1, 1977. (incorporated by reference to Registration No. 2-61502, Exhibit 2-D(1) to 2-D(19)) | |
| 4-1(b) | Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1978. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(2)) | |
| 4-1(c) | Supplemental Indenture of Pennsylvania Electric Company dated June 1, 1979. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(3)) | |
| 4-1(d) | Supplemental Indenture of Pennsylvania Electric Company, dated September 1, 1984. |
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| (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(4)) | ||
| 4-1(e) | Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1985. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(5)) | |
| 4-1(f) | Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1986. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(6)) | |
| 4-1(g) | Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 1989. (incorporated by reference to Registration No. 33-49669, Exhibit 4-A(7)) | |
| 4-1(h) | Supplemental Indenture of Pennsylvania Electric Company, dated December 1, 1990. (incorporated by reference to Registration No. 33-45312, Exhibit 4-A(8)) | |
| 4-1(i) | Supplemental Indenture of Pennsylvania Electric Company, dated March 1, 1992. (incorporated by reference to Registration No. 33-45312, Exhibit 4-A(9)) | |
| 4-1(j) | Supplemental Indenture of Pennsylvania Electric Company, dated June 1, 1993. (incorporated by reference to GPU, Inc.’s Form U5S filed May 2, 1994, Exhibit C-73, File No. 001-06047) | |
| 4-1(k) | Supplemental Indenture of Pennsylvania Electric Company, dated November 1, 1995. (incorporated by reference to 1995 Form 10-K, Exhibit 4-C-11, File No. 1-3522) | |
| 4-1(l) | Supplemental Indenture of Pennsylvania Electric Company, dated August 15, 1996. (incorporated by reference to Penelec’s Form 10-K filed March 10, 1997, Exhibit 4-C-12, File No. 001-03522) | |
| 4-1(m) | Supplemental Indenture of Pennsylvania Electric Company, dated May 1, 2001. (incorporated by reference to Penelec’s Form 10-K filed April 1, 2002, Exhibit 4-C-16, File No. 001-03522) | |
| 4-2 | Senior Note Indenture between Pennsylvania Electric Company and United States Trust Company of New York, dated April 1, 1999. (incorporated by reference to Penelec’s Form 10-K filed March 20, 2000, Exhibit 4-C-13, File No. 001-03522) | |
| 4-2(a) | Form of Pennsylvania Electric Company 6.05% Senior Notes due 2017. (incorporated by reference to Penelec’s Form 8-K filed August 31, 2007, Exhibit 4.1, File No. 001-03522) | |
| 4-2(b) | Company Order, dated as of September 30, 2009 establishing the terms of the 5.20% Senior Notes due 2020 and 6.15% Senior Notes due 2038 (incorporated by reference to Penelec’s Form 8-K filed October 6, 2009, Exhibit 4.1, File No. 001-03522) | |
| 4-2(c) | Supplemental Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of April 1, 2009, as amended, between Pennsylvania Electric Company and The Bank of New York Mellon, as successor trustee (incorporated by reference to Penelec’s Form 8-K filed October 6, 2009, Exhibit 4.4, File No. 001-03522) | |
| 4-2(d) | Agreement of Resignation, Appointment and Acceptance among The Bank of New York Mellon, as Resigning Trustee, The Bank of New York Mellon Trust Company, N.A., as Successor Trustee and Pennsylvania Electric Company, dated October 1, 2009 (incorporated by reference to Penelec’s Form 8-K filed on October 6, 2009, Exhibit 4.5, File No. 001-03522) | |
| (A) 12-8 | Consolidated ratios of earnings to fixed charges. | |
| (A) 23-7 | Consent of Independent Registered Public Accounting Firm. | |
| (A) 31-1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 31-2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-15(e)/15d-15(e). | |
| (A) 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. §1350. | |
| (A) | Provided here in electronic format as an exhibit. |
3. Exhibits — Common Exhibits for FES, Met-Ed and Penelec
| 10-1 | Notice of Termination Tolling Agreement dated as of April 7, 2006; Restated Partial Requirements Agreement, dated January 1, 2003, by and among, Metropolitan Edison Company, Pennsylvania Electric Company, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., as amended by a First Amendment to Restated Requirements Agreement, dated August 29, 2003 and by a Second Amendment to Restated Requirements Agreement, dated June 8, 2004 (“Partial Requirements Agreement”). (incorporated by reference to Met-Ed’s Form 10-Q filed May 9, 2006, Exhibit 10-5, File No. 001-00446) |
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| 10-2 | Third Restated Partial Requirements Agreement, among Metropolitan Edison Company, Pennsylvania Electric Company, a Pennsylvania corporation, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., dated November 1, 2008. (incorporated by reference to Met-Ed’s Form 10-Q filed November 7, 2008, Exhibit 10-2, File No. 001-00446) | |
| 10-3 | Fourth Restated Partial Requirements Agreement, among Metropolitan Edison Company, Pennsylvania Electric Company, a Pennsylvania corporation, The Waverly Electric Power and Light Company and FirstEnergy Solutions Corp., dated November 1, 2008. (incorporated by reference to Met-Ed’s Form 10-Q filed November 9, 2009, Exhibit 10.2, File No. 001-00446) |
3. Exhibits — Common Exhibits for FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec
| 10-1 | $2,750,000,000 Credit Agreement dated as of August 24, 2006 among FirstEnergy Corp., FirstEnergy Solutions Corp., American Transmission Systems, Inc., Ohio Edison Company, Pennsylvania Power Company, The Cleveland Electric Illuminating Company, The Toledo Edison Company Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company, as Borrowers, the banks party thereto, the fronting banks party thereto and the swing line lenders party thereto. (incorporated by reference to FE’s Form 8-K filed August 24, 2006, Exhibit 10-1, File No. 333-21011) | |
| 10-2 | Consent and Amendment to $2,750,000,000 Credit Agreement dated November 2, 2007. (incorporated by reference to FE’s Form 10-K filed February 29, 2008, Exhibit 10-2, File No. 333-21011) |
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Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholders and Board of Directors of
FirstEnergy Corp.:
FirstEnergy Corp.:
Our audits of the consolidated financial statements and of the effectiveness of internal control over financial reporting referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
FirstEnergy Solutions Corp.:
FirstEnergy Solutions Corp.:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
Ohio Edison Company:
Ohio Edison Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
The Cleveland Electric Illuminating Company:
The Cleveland Electric Illuminating Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
The Toledo Edison Company:
The Toledo Edison Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
Jersey Central Power & Light Company:
Jersey Central Power & Light Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
Metropolitan Edison Company:
Metropolitan Edison Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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Table of Contents
Report of Independent Registered Public Accounting Firm
on
Financial Statement Schedule
on
Financial Statement Schedule
To the Stockholder and Board of Directors of
Pennsylvania Electric Company:
Pennsylvania Electric Company:
Our audits of the consolidated financial statements referred to in our report dated February 16, 2011 also included an audit of the financial statement schedule listed in Item 15(a)(2) of this Form 10-K. In our opinion, this financial statement schedule presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
| /s/ PricewaterhouseCoopers LLP | ||
| PricewaterhouseCoopers LLP | ||
| Cleveland, Ohio | ||
| February 16, 2011 |
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SCHEDULE II
FIRSTENERGY CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 33,431 | $ | 59,750 | $ | 37,813 | (a) | $ | 94,722 | (b) | $ | 36,272 | ||||||||
| — others | $ | 6,969 | $ | 2,687 | $ | 1,037 | (a) | $ | 2,441 | (b) | $ | 8,252 | ||||||||
| Loss carryforward tax valuation reserve | $ | 21,282 | $ | (65 | ) | $ | — | $ | — | $ | 21,217 | |||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 27,847 | $ | 67,503 | $ | 32,975 | (a) | $ | 94,894 | (b) | $ | 33,431 | ||||||||
| — others | $ | 9,167 | $ | (405 | ) | $ | 10,457 | (a) | $ | 12,250 | (b) | $ | 6,969 | |||||||
| Loss carryforward tax valuation reserve | $ | 27,294 | $ | (1,091 | ) | $ | (4,921 | ) | $ | — | $ | 21,282 | ||||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 35,567 | $ | 48,297 | $ | 31,308 | (a) | $ | 87,325 | (b) | $ | 27,847 | ||||||||
| — others | $ | 21,924 | $ | 11,339 | $ | 3,189 | (a) | $ | 27,285 | (b) | $ | 9,167 | ||||||||
| Loss carryforward tax valuation reserve | $ | 30,616 | $ | 1,435 | $ | (4,757 | ) | $ | — | $ | 27,294 | |||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 12,041 | $ | 9,397 | $ | — | (a) | $ | 4,847 | (b) | $ | 16,591 | ||||||||
| — other | $ | 6,702 | $ | 64 | $ | — | (a) | $ | 1 | (b) | $ | 6,765 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 5,899 | $ | 7,745 | $ | — | (a) | $ | 1,603 | (b) | $ | 12,041 | ||||||||
| — other | $ | 6,815 | $ | (161 | ) | $ | 57 | (a) | $ | 9 | (b) | $ | 6,702 | |||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 8,072 | $ | 649 | $ | 110 | (a) | $ | 2,932 | (b) | $ | 5,899 | ||||||||
| — other | $ | 9 | $ | 4,374 | $ | 2,541 | (a) | $ | 109 | (b) | $ | 6,815 | ||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
307
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SCHEDULE II
OHIO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 5,119 | $ | 6,588 | $ | 11,074 | (a) | $ | 18,695 | (b) | $ | 4,086 | ||||||||
| — other | $ | 18 | $ | 5 | $ | 180 | (a) | $ | 197 | (b) | $ | 6 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 6,065 | $ | 16,230 | $ | 11,252 | (a) | $ | 28,428 | (b) | $ | 5,119 | ||||||||
| — other | $ | 7 | $ | 17 | $ | 326 | (a) | $ | 332 | (b) | $ | 18 | ||||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 8,032 | $ | 12,179 | $ | 10,027 | (a) | $ | 24,173 | (b) | $ | 6,065 | ||||||||
| — other | $ | 5,639 | $ | 16,618 | $ | 394 | (a) | $ | 22,644 | (b) | $ | 7 | ||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 5,239 | $ | 14,716 | $ | 11,151 | (a) | $ | 26,517 | (b) | $ | 4,589 | ||||||||
| — other | $ | 21 | $ | 33 | $ | 50 | (a) | $ | 103 | (b) | $ | 1 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 5,916 | $ | 16,764 | $ | 8,942 | (a) | $ | 26,383 | (b) | $ | 5,239 | ||||||||
| — other | $ | 11 | $ | 50 | $ | 51 | (a) | $ | 91 | (b) | $ | 21 | ||||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 7,540 | $ | 11,323 | $ | 9,179 | (a) | $ | 22,126 | (b) | $ | 5,916 | ||||||||
| — other | $ | 433 | $ | (183 | ) | $ | 30 | (a) | $ | 269 | (b) | $ | 11 | |||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
THE TOLEDO EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | — | $ | 2 | $ | — | (a) | $ | 1 | (b) | $ | 1 | ||||||||
| — other | $ | 208 | $ | 127 | $ | 13 | (a) | $ | 18 | (b) | $ | 330 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — other | $ | 203 | $ | (115 | ) | $ | 165 | (a) | $ | 45 | (b) | $ | 208 | |||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — other | $ | 615 | $ | (247 | ) | $ | 121 | (a) | $ | 286 | (b) | $ | 203 | |||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,506 | $ | 12,487 | $ | 5,251 | (a) | $ | 17,475 | (b) | $ | 3,769 | ||||||||
| — other | $ | — | $ | 209 | $ | 70 | (a) | $ | 257 | (b) | $ | 22 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,230 | $ | 11,519 | $ | 5,424 | (a) | $ | 16,667 | (b) | $ | 3,506 | ||||||||
| — other | $ | 45 | $ | (37 | ) | $ | 380 | (a) | $ | 388 | (b) | $ | — | |||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,691 | $ | 10,377 | $ | 3,504 | (a) | $ | 14,342 | (b) | $ | 3,230 | ||||||||
| — other | $ | — | $ | 44 | $ | 24 | (a) | $ | 23 | (b) | $ | 45 | ||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
METROPOLITAN EDISON COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 4,044 | $ | 10,021 | $ | 5,248 | (a) | $ | 15,445 | (b) | $ | 3,868 | ||||||||
| — other | $ | — | $ | 14 | $ | 39 | (a) | $ | 53 | (b) | $ | — | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,616 | $ | 9,583 | $ | 3,926 | (a) | $ | 13,081 | (b) | $ | 4,044 | ||||||||
| — other | $ | — | $ | 8 | $ | 26 | (a) | $ | 34 | (b) | $ | — | ||||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 4,327 | $ | 9,004 | $ | 3,729 | (a) | $ | 13,444 | (b) | $ | 3,616 | ||||||||
| — other | $ | 1 | $ | 19 | $ | 21 | (a) | $ | 41 | (b) | $ | — | ||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SCHEDULE II
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
FOR THE YEARS ENDED DECEMBER 31, 2010, 2009 AND 2008
| Additions | ||||||||||||||||||||
| Charged | ||||||||||||||||||||
| Beginning | Charged | to Other | Ending | |||||||||||||||||
| Description | Balance | to Income | Accounts | Deductions | Balance | |||||||||||||||
| (In thousands) | ||||||||||||||||||||
Year Ended December 31, 2010: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,483 | $ | 6,538 | $ | 5,088 | (a) | $ | 11,740 | (b) | $ | 3,369 | ||||||||
| — other | $ | 3 | $ | 5 | $ | 684 | (a) | $ | 691 | (b) | $ | 1 | ||||||||
Year Ended December 31, 2009: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,121 | $ | 7,264 | $ | 3,431 | (a) | $ | 10,333 | (b) | $ | 3,483 | ||||||||
| — other | $ | 65 | $ | (57 | ) | $ | 7,557 | (a) | $ | 7,562 | (b) | $ | 3 | |||||||
Year Ended December 31, 2008: | ||||||||||||||||||||
| Accumulated provision for uncollectible accounts — customers | $ | 3,905 | $ | 7,589 | $ | 4,758 | (a) | $ | 13,131 | (b) | $ | 3,121 | ||||||||
| — other | $ | 105 | $ | 57 | $ | 36 | (a) | $ | 133 | (b) | $ | 65 | ||||||||
| (a) | Represents recoveries and reinstatements of accounts previously written off. | |
| (b) | Represents the write-off of accounts considered to be uncollectible. |
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| FIRSTENERGY CORP. | ||||
| BY: | /s/ Anthony J. Alexander | |||
| Anthony J. Alexander | ||||
| President and Chief Executive Officer | ||||
Date: February 16, 2011
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ George M. Smart | /s/ Anthony J. Alexander | |||||
| Chairman of the Board | President and Chief Executive Officer and Director | |||||
| (Principal Executive Officer) | ||||||
/s/ Mark T. Clark | /s/ Harvey L. Wagner | |||||
| Executive Vice President and Chief Financial Officer | Vice President, Controller and Chief Accounting Officer | |||||
| (Principal Financial Officer) | (Principal Accounting Officer) | |||||
/s/ Paul T. Addison | ||||||
| Director | ||||||
/s/ Michael J. Anderson | /s/ Ernest J. Novak, Jr. | |||||
| Director | Director | |||||
/s/ Carol A. Cartwright | /s/ Catherine A. Rein | |||||
| Director | Director | |||||
/s/ William T. Cottle | /s/ Wes M. Taylor | |||||
| Director | Director | |||||
/s/ Robert B. Heisler, Jr. | /s/ Jesse T. Williams, Sr. | |||||
| Director | Director |
Date: February 16, 2011
315
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| FIRSTENERGY SOLUTIONS CORP. | ||||
| BY: | /s/ Donald R. Schneider | |||
| Donald R. Schneider | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Donald R. Schneider President (Principal Executive Officer) | /s/ Mark T. Clark Executive Vice President and Chief Financial Officer and Director (Principal Financial Officer) | |||||
/s/ Anthony J. Alexander | /s/ Harvey L. Wagner | |||||
| Director | Vice President and Controller | |||||
| (Principal Accounting Officer) | ||||||
/s/ Gary R. Leidich | ||||||
| Director |
Date: February 16, 2011
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| OHIO EDISON COMPANY | ||||
| BY: | /s/ Charles E. Jones | |||
| Charles E. Jones | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Anthony J. Alexander | /s/ Charles E. Jones | |||||
| Director | President and Director | |||||
| (Principal Executive Officer) | ||||||
/s/ Mark T. Clark | /s/ Harvey L. Wagner | |||||
| Executive Vice President and Chief | Vice President and Controller | |||||
| Financial Officer and Director | (Principal Accounting Officer) | |||||
| (Principal Financial Officer) |
Date: February 16, 2011
317
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | ||||
| BY: | /s/ Charles E. Jones | |||
| Charles E. Jones | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Anthony J. Alexander | /s/ Charles E. Jones | |||||
| Director | President and Director (Principal Executive Officer) | |||||
/s/ Mark T. Clark | /s/ Harvey L. Wagner | |||||
| Executive Vice President and Chief | Vice President and Controller | |||||
| Financial Officer and Director | (Principal Accounting Officer) | |||||
| (Principal Financial Officer) |
Date: February 16, 2011
318
Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| THE TOLEDO EDISON COMPANY | ||||
| BY: | /s/ Charles E. Jones | |||
| Charles E. Jones | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Anthony J. Alexander | /s/ Charles E. Jones | |||||
| Director | President and Director | |||||
| (Principal Executive Officer) | ||||||
/s/ Mark T. Clark | /s/ Harvey L. Wagner | |||||
| Executive Vice President and Chief | Vice President and Controller | |||||
| Financial Officer and Director | (Principal Accounting Officer) | |||||
| (Principal Financial Officer) |
Date: February 16, 2011
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Table of Contents
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| JERSEY CENTRAL POWER & LIGHT COMPANY | ||||
| BY: | /s/ Donald M. Lynch | |||
| Donald M. Lynch | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Donald M. Lynch | /s/ K. Jon Taylor | |||||
| President and Director | Controller | |||||
| (Principal Executive Officer) | (Principal Financial and Accounting Officer) | |||||
/s/ Charles E. Jones | /s/ Gelorma E. Persson | |||||
| Director | Director | |||||
/s/ Mark A. Julian | /s/ Jesse T. Williams, Sr. | |||||
| Director | Director |
Date: February 16, 2011
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| METROPOLITAN EDISON COMPANY | ||||
| BY: | /s/ Charles E. Jones | |||
| Charles E. Jones | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Charles E. Jones | /s/ Mark T. Clark | |||||
| President and Director | Executive Vice President and Chief | |||||
| (Principal Executive Officer) | Financial Officer (Principal Financial Officer) | |||||
/s/ Donald A. Brennan | /s/ Harvey L. Wagner | |||||
| Regional President and Director | Vice President and Controller | |||||
| (Principal Accounting Officer) | ||||||
/s/ Randy Scilla | ||||||
| Assistant Treasurer and Director |
Date: February 16, 2011
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| PENNSYLVANIA ELECTRIC COMPANY | ||||
| BY: | /s/ Charles E. Jones | |||
| Charles E. Jones | ||||
| President | ||||
Date: February 16, 2011
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the date indicated:
/s/ Charles E. Jones | /s/ Mark T. Clark | |||||
| President and Director | Executive Vice President and Chief | |||||
| (Principal Executive Officer) | Financial Officer | |||||
| (Principal Financial Officer) | ||||||
/s/ John E. Skory | /s/ Harvey L. Wagner | |||||
| Regional President and Director | Vice President and Controller | |||||
| (Principal Accounting Officer) | ||||||
/s/ Randy Scilla | ||||||
| Assistant Treasurer and Director |
Date: February 16, 2011
322