UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
FORM 10-Q
(Mark One)
[X] | | |
| þ | | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 20102011
OR
[ ] 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 |
| Address; and Telephone Number
| |
| | | |
| o | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period fromto
| | | | |
| Commission | | Registrant; State of Incorporation; | | I.R.S. Employer |
| File Number | | Address; and Telephone Number | | Identification No. |
|
| 333-21011 | | FIRSTENERGY CORP.
(An Ohio Corporation)
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 34-1843785 |
| | (An Ohio Corporation) | |
| 76 South Main Street | |
| Akron, OH 44308 | |
| Telephone (800)736-3402
| |
| | | |
| 000-53742 | | FIRSTENERGY SOLUTIONS CORP.
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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
(An Ohio Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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
(A New Jersey Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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
(A Pennsylvania Corporation)
c/o FirstEnergy Corp.
76 South Main Street
Akron, OH 44308
Telephone (800)736-3402 | | 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 | |
| Telephone (800)736-3402
| 25-0718085 |
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.
| | |
|
YesYes (X)þ No( )o | | 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 |
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).
| | |
|
YesYes (X)þ No( )o | | FirstEnergy Corp. |
| | |
|
YesYes ( )o No( )o | | 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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large“large accelerated filer," "accelerated filer"” “accelerated filer” and "smaller“smaller reporting company"company” in Rule 12b-2 of the Exchange Act.
| | |
|
Large Accelerated Filerþ (X)
| | FirstEnergy Corp. |
| | |
Accelerated Filero ( )
| | N/A |
| | |
Non-accelerated Filer (Do not check if a smaller reporting company)þ (X)
| | 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 Company
( )
| | N/A |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
| | |
|
YesYes ( )o No(X)þ | | 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 |
Indicate the number of shares outstanding of each of the issuer'sissuer’s classes of common stock, as of the latest practicable date:
| | | | | |
| | OUTSTANDING | |
| CLASS | | AS OF APRIL 30, 2010April 29, 2011 | |
| FirstEnergy Corp., $.10 par value | 304,835,407 | | 418,216,437 | |
| 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 | 859,500 | | 740,905 | |
| 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.
This combined Form 10-Q 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.
FirstEnergy Web Site
Each of the registrants’ 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 WebFirstEnergy’s Internet web site at www.firstenergycorp.com.
These reports are posted on the Webweb site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on the WebFirstEnergy’s Internet web site and recognize the WebFirstEnergy’s Internet web site isas 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 WebFirstEnergy’s Internet web site shall not be deemed incorporated into, or to be part of, this report.
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 H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.
Forward-Looking Statements:This Form 10-Q 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 f orward-lookingforward-looking statements.
Actual results may differ materially due to:
· | The speed and nature of increased competition in the electric utility industry and legislative and regulatory changes affecting how generation rates will be determined following the expiration of existing rate plans in Pennsylvania. |
The speed and nature of increased competition in the electric utility industry.
· | The impact of the regulatory process on the pending matters in Ohio, Pennsylvania and New Jersey. |
The impact of the regulatory process on the pending matters in the various states in which we do business including, but not limited to, matters related to rates.
· | Business and regulatory impacts from ATSI’s realignment into PJM. |
The status of the PATH project in light of PJM’s direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.
· | Economic or weather conditions affecting future sales and margins. |
Business and regulatory impacts from ATSI’s realignment into PJM Interconnection, L.L.C.
· | Changes in markets for energy services. |
Economic or weather conditions affecting future sales and margins.
· | Changing energy and commodity market prices and availability. |
Changes in markets for energy services.
· | Replacement power costs being higher than anticipated or inadequately hedged. |
Changing energy and commodity market prices and availability.
· | The continued ability of FirstEnergy’s regulated utilities to collect transition and other charges or to recover increased transmission costs. |
Financial derivative reforms that could increase our liquidity needs and collateral costs.
· | Operation and maintenance costs being higher than anticipated. |
Replacement power costs being higher than anticipated or inadequately hedged.
· | Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission regulations. |
The continued ability of FirstEnergy’s regulated utilities to collect transition and other costs.
· | The potential impacts of the U.S. Court of Appeals’ July 11, 2008 decision requiring revisions to the CAIR rules and the scope of any laws, rules or regulations that may ultimately take their place. |
Operation and maintenance costs being higher than anticipated.
· | The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated or that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential similar regulatory initiatives or actions. |
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric 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. |
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).
· | Factors that may further delay, or increase the costs associated with (including replacement power costs), the restart of the Davis-Besse Nuclear Power Station from its current refueling outage, including that the modifications to control rod drive mechanism nozzles take longer than expected or are not effective, other conditions requiring remediation are discovered during the extended outage, or the NRC takes adverse action in connection with any of the foregoing. |
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, including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant.
· | Ultimate resolution of Met-Ed’s and Penelec’s TSC filings with the PPUC. |
Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s transmission service charge appeal at the Commonwealth Court of Pennsylvania.
· | The continuing availability of generating units and their ability to operate at or near full capacity. |
The continuing availability of generating units and changes in their ability to operate at or near full capacity.
· | The ability to comply with applicable state and federal reliability standards and energy efficiency mandates. |
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
· | The ability to accomplish or realize anticipated benefits from strategic goals (including employee workforce initiatives). |
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 improve electric commodity margins and to experience growth in the distribution business. |
The ability to accomplish or realize anticipated benefits from strategic goals.
· | 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. |
Efforts and our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.
· | 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. |
The ability to experience growth in the distribution business.
· | Changes in general economic conditions affecting the registrants. |
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, the cost of such capital and overall condition of the capital and credit markets affecting the registrants and other FirstEnergy subsidiaries.
· | The state of the capital and credit markets affecting the registrants. |
Changes in general economic conditions affecting the registrants and other FirstEnergy subsidiaries.
· | 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. |
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 decline of the national and regional economy and its impact on the registrants’ major industrial and commercial customers. |
The continuing uncertainty of the national and regional economy and its impact on the registrants’ major industrial and commercial customers and those of other FirstEnergy subsidiaries.
· | Issues concerning the soundness of financial institutions and counterparties with which the registrants do business. |
Issues concerning the soundness of financial institutions and counterparties with which the registrants and FirstEnergy’s other subsidiaries do business.
· | The expected timing and likelihood of completion of the proposed merger with Allegheny Energy, Inc., 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. |
Issues arising from the recently completed merger of FirstEnergy and Allegheny Energy, Inc. and the ongoing coordination of their combined operations including FirstEnergy’s 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. |
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. A security rating is not a recommendation to buy, or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.
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. A security rating is not a recommendation to buy, sell or hold securities that may be subject to revision or withdrawal at any time by the assigning rating organization. Each rating should be evaluated independently of any other rating. The registrants expressly disclaim any current intention to update any forward-looking statements contained herein as a result of new information, future events or ot herwise.otherwise.
TABLE OF CONTENTS
| | | Pages | | |
| | | |
Glossary of Terms
| iii-ivPage | |
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| | iii-v | |
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FirstEnergy Corp. | | | | |
| | | | | |
| | | 1 | |
| | | | | |
| | | 2 | |
| | | | | |
| | | 3 | |
| | | | | |
| | | 4 | |
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FirstEnergy Solutions Corp. | | | | |
| | | | | |
| | | | 5 | |
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| | | 6 | |
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| | | 7 | |
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Ohio Edison Company | | | | |
| | | | | |
| | | | 8 | |
| | | | | |
| | | 9 | |
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| | | 10 | |
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The Cleveland Electric Illuminating Company | | | | |
| | | | | |
| | | | 11 | |
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| | | 12 | |
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| | | 13 | |
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The Toledo Edison Company | | | | |
| | | | | |
| | | | 14 | |
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| | | 15 | |
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| | | 16 | |
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Jersey Central Power & Light Company | | | | |
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| | | | 17 | |
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| | | 18 | |
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| | | 19 | |
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Metropolitan Edison Company | | | | |
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| | | | 20 | |
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| | | 21 | |
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| | | 22 | |
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Pennsylvania Electric Company | | | | |
| | | | | |
| | | | 23 | |
| | | | | |
| | | 24 | |
| | Consolidated Statements of Cash Flows | 25 | |
TABLE OF CONTENTS (Cont'd)
i
TABLE OF CONTENTS (Cont’d)
ii
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and its current and former subsidiaries:
| | |
|
| AE | | Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011 |
| AESC | | Allegheny Energy Service Corporation, a subsidiary of AE |
| AE Supply | | Allegheny Energy Supply Company LLC, an unregulated generation subsidiary of AE |
| AGC | | Allegheny Generating Company, a generation subsidiary of AE |
| Allegheny | | Allegheny Energy, Inc., together with its consolidated subsidiaries |
| AVE | | Allegheny Ventures, Inc. |
| ATSI | | American Transmission Systems, Incorporated, which owns and operates transmission facilities |
| CEI | | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary |
| FENOC | | FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities |
| FES | | FirstEnergy Solutions Corp., which provides energy-related products and services |
| FESC | | FirstEnergy Service Company, which provides legal, financial and other corporate support services |
| FEV | | FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures |
| FGCO | | FirstEnergy Generation Corp., which owns and operates non-nuclear generating facilities |
| FirstEnergy | | FirstEnergy Corp., a public utility holding company |
| Global Rail | | A joint venture between FEV 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, whichthat merged with FirstEnergy onNovember 7, 2001 |
| JCP&L | | Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary |
JCP&L Transition
Funding
Met-Ed | 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 |
| MP | | Monongahela Power Company, a West Virginia electric utility operating subsidiary of AE |
| 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 |
| PATH | | Potomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc. |
| PATH-VA | | PATH Allegheny Virginia Transmission Corporation |
| PE | | The Potomac Edison Company, a Maryland electric operating subsidiary of AE |
| 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, Penn and PennWP |
| PNBV | | PNBV Capital Trust, a special purpose entity created by OE in 1996 |
Shelf RegistrantsShippingport | 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 FirstEnergyFEV and WMB Loan Ventures Corp. and Boich Companies,LLC, that owns mining and coal transportation operations near Roundup, Montana
|
| TE | | The Toledo Edison Company, an Ohio electric utility operating subsidiary |
| TrAIL | | Trans-Allegheny Interstate Line Company |
| Utilities | | OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP |
| Utility Registrants | | OE, CEI, TE, JCP&L, Met-Ed and Penelec |
WaverlyWP | The Waverly | West Penn Power and Light Company, a wholly ownedPennsylvania electric utility operating subsidiary of PenelecAE |
The following abbreviations and acronyms are used to identify frequently used terms in this report:
| | |
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 |
AMP-OhioAOCL | American Municipal Power-Ohio, Inc. |
AOCL | Accumulated Other Comprehensive Loss |
| AEP | | American Electric Power |
| AQC | | Air Quality Control |
| ARO | | Asset Retirement Obligation |
| BGS | | Basic Generation Service |
| CAA | | Clean Air Act |
| CAIR | | Clean Air Interstate Rule |
| CAMR | | Clean Air Mercury Rule |
CAVRCATR | | Clean Air VisibilityTransport Rule |
| CBP | | Competitive Bid Process |
CMECCDWR | Capacity market Evolution Committee | California Department of Water Resources |
CO2 | | Carbon dioxideDioxide |
| CTC | | Competitive Transition Charge |
iii
GLOSSARY OF TERMS, Cont’d.
| | |
|
| DCPD | | Deferred Compensation Plan for Outside Directors |
| DOE | | United States Department of Energy |
| DOJ | | United States Department of Justice |
DCPDDPA | Deferred Compensation Plan for Outside Directors |
DPA | Department of the Public Advocate, Division of Rate Counsel (New Jersey) |
ECARDSP | East Central Area Reliability Coordination Agreement | Default Service Plan |
| EDCP | | Executive Deferred Compensation Plan |
| EE&C | | Energy Efficiency and Conservation |
| EIS | | Energy Insurance Services, Inc. |
| EMP | | Energy Master Plan |
| ENEC | | Expanded Net Energy Cost |
| EPA | | United States Environmental Protection Agency |
EPACTESOP | Energy Policy Act of 2005 |
EPRI | Electric Power Research Institute |
GLOSSARY OF TERMS, Cont'd.
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 |
| FTRs | | Financial Transmission Rights |
| GAAP | | Generally Accepted Accounting Principles Generally Accepted in the United States |
| RGGI | | Regional Greenhouse Gas Initiative |
| GHG | | Greenhouse Gases |
IBEWIRS | International Brotherhood of Electrical Workers |
IFRS | International Financial Reporting Standards |
IRS | Internal Revenue Service |
JCARRJOA | | Joint Committee on Agency ReviewOperating Agreement |
| kV | | Kilovolt |
| KWH | | Kilowatt-hours |
| LED | Light-emitting | Light-Emitting Diode |
LIBORLOC | London Interbank Offered Rate |
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'sMoody’s | Moody's | Moody’s Investors Service, Inc. |
| MRO | | Market Rate Offer |
| MSHA | | Mine Safety and Health Administration |
| MTEP | | MISO Regional Transmission Expansion Plan |
| MW | | Megawatts |
| MWH | | Megawatt-hours |
| NAAQS | | National Ambient Air Quality Standards |
NEILNDT | | Nuclear Electric Insurance LimitedDecommissioning Trusts |
| 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 |
| NYSEG | | New York State Electric and Gas |
| OCC | | Ohio Consumers’ Counsel |
| OCI | | Other Comprehensive Income |
| OPEB | | Other Post-Employment Benefits |
| OVEC | | Ohio Valley Electric Corporation |
| PADEP | | Pennsylvania Department of Environmental Protection |
| PCRB | | Pollution Control Revenue Bond |
| PICA | | Pennsylvania Intergovernmental Cooperation Authority |
| PJM | | PJM Interconnection L. L. C. |
PLRPOLR | | Provider of Last Resort; an electric utility'sutility’s obligation to provide generation service to customers whose Whose alternative supplier fails to deliver service
|
| PPUC | | Pennsylvania Public Utility Commission |
iv
GLOSSARY OF TERMS, Cont’d.
| | |
|
| PSCWV | | Public Service Commission of West Virginia |
| PSA | | Power Supply Agreement |
| PSD | | Prevention of Significant Deterioration |
| PUCO | | Public Utilities Commission of Ohio |
QSPEPURPA | Qualifying Special-Purpose Entity |
RCP | Rate Certainty PlanPublic Utility Regulatory Policies Act of 1978 |
| RECs | | Renewable Energy Credits |
| RFP | | Request for Proposal |
RPMRGGI | Reliability Pricing Model | Regional Greenhouse Gas Initiative |
| RTEP | | Regional Transmission Expansion Plan |
| RTC | | Regulatory Transition Charge |
| RTO | | Regional Transmission Organization |
| S&P | | Standard & Poor'sPoor’s Ratings Service |
| SB221 | | Amended Substitute Senate Bill 221 |
| SBC | | Societal Benefits Charge |
| SEC | | U.S. Securities and Exchange Commission |
SECASIP | Seams Elimination Cost Adjustment |
GLOSSARY OF TERMS, Cont'd.
SIP | State Implementation Plan(s) Under the Clean Air Act |
| SMIP | | Smart Meter Implementation Plan |
| SNCR | | Selective Non-Catalytic Reduction |
SO2 | | Sulfur Dioxide |
SRECsSOS | Solar Renewable Energy Credits | Standard Offer Service |
| TBC | | Transition Bond Charge |
| TDS | | Total Dissolved Solid |
| TMDL | | Total Maximum Daily Load |
| TMI-2 | | Three Mile Island Unit 2 |
| TSC | | Transmission Service Charge |
VEROVIE | Voluntary Enhanced Retirement Option |
VIE | Variable Interest Entity |
| VSCC | | Virginia State Corporation Commission |
| WVDEP | | West Virginia Department of Environmental Protection |
| WVPSC | | Public Service Commission of West Virginia |
v
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited) | | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| In millions, except per share amounts | | 2011 | | | 2010 | |
| | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric utilities | | $ | 2,332 | | | $ | 2,543 | |
| Unregulated businesses | | | 1,244 | | | | 756 | |
| | | | | | | |
| Total revenues* | | | 3,576 | | | | 3,299 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Fuel | | | 453 | | | | 334 | |
| Purchased power | | | 1,186 | | | | 1,238 | |
| Other operating expenses | | | 1,033 | | | | 701 | |
| Provision for depreciation | | | 220 | | | | 193 | |
| Amortization of regulatory assets | | | 132 | | | | 212 | |
| General taxes | | | 237 | | | | 205 | |
| | | | | | | |
| Total expenses | | | 3,261 | | | | 2,883 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 315 | | | | 416 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 21 | | | | 16 | |
| Interest expense | | | (231 | ) | | | (213 | ) |
| Capitalized interest | | | 18 | | | | 41 | |
| | | | | | | |
| Total other expense | | | (192 | ) | | | (156 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 123 | | | | 260 | |
| | | | | | | | | |
INCOME TAXES | | | 78 | | | | 111 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | | 45 | | | | 149 | |
| | | | | | | | | |
| Loss attributable to noncontrolling interest | | | (5 | ) | | | (6 | ) |
| | | | | | | |
| | | | | | | | | |
EARNINGS AVAILABLE TO FIRSTENERGY CORP. | | $ | 50 | | | $ | 155 | |
| | | | | | | |
| | | | | | | | | |
BASIC EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.15 | | | $ | 0.51 | |
| | | | | | | |
| | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 342 | | | | 304 | |
| | | | | | | |
| | | | | | | | | |
DILUTED EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.15 | | | $ | 0.51 | |
| | | | | | | |
| | | | | | | | | |
WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 343 | | | | 306 | |
| | | | | | | |
| | | | | | | | | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.55 | | | $ | 0.55 | |
| | | | | | | |
| | |
| * | | Includes $119 and $109 million of excise tax collections in the three months ended March 31, 2011 and 2010, respectively. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
1
FIRSTENERGY CORP.
| FIRSTENERGY CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In millions, except | |
| | | per share amounts) | |
| REVENUES: | | | | | | |
| Electric utilities | | $ | 2,543 | | | $ | 3,020 | |
| Unregulated businesses | | | 756 | | | | 314 | |
| Total revenues* | | | 3,299 | | | | 3,334 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Fuel | | | 334 | | | | 312 | |
| Purchased power | | | 1,238 | | | | 1,143 | |
| Other operating expenses | | | 701 | | | | 827 | |
| Provision for depreciation | | | 193 | | | | 177 | |
| Amortization of regulatory assets | | | 212 | | | | 411 | |
| Deferral of new regulatory assets | | | - | | | | (93 | ) |
| General taxes | | | 205 | | | | 211 | |
| Total expenses | | | 2,883 | | | | 2,988 | |
| | | | | | | | | |
| OPERATING INCOME | | | 416 | | | | 346 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income (loss), net | | | 16 | | | | (11 | ) |
| Interest expense | | | (213 | ) | | | (194 | ) |
| Capitalized interest | | | 41 | | | | 28 | |
| Total other expense | | | (156 | ) | | | (177 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 260 | | | | 169 | |
| | | | | | | | | |
| INCOME TAXES | | | 111 | | | | 54 | |
| | | | | | | | | |
| NET INCOME | | | 149 | | | | 115 | |
| | | | | | | | | |
| Noncontrolling interest loss | | | (6 | ) | | | (4 | ) |
| | | | | | | | | |
| EARNINGS AVAILABLE TO FIRSTENERGY CORP. | | $ | 155 | | | $ | 119 | |
| | | | | | | | | |
| | | | | | | | | |
| BASIC EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.51 | | | $ | 0.39 | |
| | | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 304 | | | | 304 | |
| | | | | | | | | |
| DILUTED EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.51 | | | $ | 0.39 | |
| | | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 306 | | | | 306 | |
| | | | | | | | | |
| DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 0.55 | | | $ | 0.55 | |
| | | | | | | | | |
| | | | | | | | | |
| * Includes $109 million of excise tax collections in the three months ended March 31, 2010 and 2009. | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In millions) | | 2011 | | | 2010 | |
| | | | | | | | | |
NET INCOME | | $ | 45 | | | $ | 149 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 19 | | | | 13 | |
| Unrealized gain (loss) on derivative hedges | | | (6 | ) | | | 4 | |
| Change in unrealized gain on available-for-sale securities | | | 9 | | | | 6 | |
| | | | | | | |
| Other comprehensive income | | | 22 | | | | 23 | |
| Income tax expense related to other comprehensive income | | | 1 | | | | 7 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 21 | | | | 16 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | | 66 | | | | 165 | |
| | | | | | | | | |
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | (5 | ) | | | (6 | ) |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. | | $ | 71 | | | $ | 171 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
2
CONSOLIDATED BALANCE SHEETS
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In millions) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 1,101 | | | $ | 1,019 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $38 in 2011 and $36 in 2010 | | | 1,636 | | | | 1,392 | |
| Other, net of allowance for uncollectible accounts of $10 in 2011 and $8 in 2010 | | | 229 | | | | 176 | |
| Materials and supplies | | | 852 | | | | 638 | |
| Prepaid taxes | | | 241 | | | | 199 | |
| Derivatives | | | 377 | | | | 182 | |
| Other | | | 210 | | | | 92 | |
| | | | | | | |
| | | | 4,646 | | | | 3,698 | |
| | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 38,168 | | | | 29,451 | |
| Less — Accumulated provision for depreciation | | | 11,345 | | | | 11,180 | |
| | | | | | | |
| | | | 26,823 | | | | 18,271 | |
| Construction work in progress | | | 2,322 | | | | 1,517 | |
| Property, plant and equipment held for sale, net | | | 490 | | | | — | |
| | | | | | | |
| | | | 29,635 | | | | 19,788 | |
| | | | | | | |
INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 2,018 | | | | 1,973 | |
| Investments in lease obligation bonds | | | 422 | | | | 476 | |
| Nuclear fuel disposal trust | | | 207 | | | | 208 | |
| Other | | | 434 | | | | 345 | |
| | | | | | | |
| | | | 3,081 | | | | 3,002 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 6,527 | | | | 5,575 | |
| Regulatory assets | | | 2,084 | | | | 1,826 | |
| Intangible assets | | | 1,075 | | | | 256 | |
| Other | | | 818 | | | | 660 | |
| | | | | | | |
| | | | 10,504 | | | | 8,317 | |
| | | | | | | |
| | | $ | 47,866 | | | $ | 34,805 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,385 | | | $ | 1,486 | |
| Short-term borrowings | | | 486 | | | | 700 | |
| Accounts payable | | | 1,080 | | | | 872 | |
| Accrued taxes | | | 412 | | | | 326 | |
| Accrued compensation and benefits | | | 312 | | | | 315 | |
| Derivatives | | | 425 | | | | 266 | |
| Other | | | 1,062 | | | | 733 | |
| | | | | | | |
| | | | 5,162 | | | | 4,698 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, $0.10 par value, authorized 490,000,000 shares- 418,216,437 shares outstanding | | | 42 | | | | 31 | |
| Other paid-in capital | | | 9,779 | | | | 5,444 | |
| Accumulated other comprehensive loss | | | (1,518 | ) | | | (1,539 | ) |
| Retained earnings | | | 4,426 | | | | 4,609 | |
| | | | | | | |
| Total common stockholders’ equity | | | 12,729 | | | | 8,545 | |
| Noncontrolling interest | | | (40 | ) | | | (32 | ) |
| | | | | | | |
| Total equity | | | 12,689 | | | | 8,513 | |
| Long-term debt and other long-term obligations | | | 17,535 | | | | 12,579 | |
| | | | | | | |
| | | | 30,224 | | | | 21,092 | |
| | | | | | | |
| | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 4,832 | | | | 2,879 | |
| Retirement benefits | | | 2,313 | | | | 1,868 | |
| Asset retirement obligations | | | 1,443 | | | | 1,407 | |
| Deferred gain on sale and leaseback transaction | | | 951 | | | | 959 | |
| Power purchase contract liability | | | 606 | | | | 466 | |
| Other | | | 2,335 | | | | 1,436 | |
| | | | | | | |
| | | | 12,480 | | | | 9,015 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 47,866 | | | $ | 34,805 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
3
FIRSTENERGY CORP.
| FIRSTENERGY CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In millions) | |
| | | | | | | |
| NET INCOME | | $ | 149 | | | $ | 115 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 13 | | | | 35 | |
| Unrealized gain on derivative hedges | | | 4 | | | | 15 | |
| Change in unrealized gain on available-for-sale securities | | | 6 | | | | (5 | ) |
| Other comprehensive income | | | 23 | | | | 45 | |
| Income tax expense related to other comprehensive income | | | 7 | | | | 15 | |
| Other comprehensive income, net of tax | | | 16 | | | | 30 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | | 165 | | | | 145 | |
| | | | | | | | | |
| COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | (6 | ) | | | (4 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. | | $ | 171 | | | $ | 149 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In millions) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 45 | | | $ | 149 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 220 | | | | 193 | |
| Amortization of regulatory assets | | | 132 | | | | 212 | |
| Nuclear fuel and lease amortization | | | 47 | | | | 41 | |
| Deferred purchased power and other costs | | | (58 | ) | | | (77 | ) |
| Deferred income taxes and investment tax credits, net | | | 171 | | | | 59 | |
| Deferred rents and lease market valuation liability | | | (15 | ) | | | (17 | ) |
| Accrued compensation and retirement benefits | | | (13 | ) | | | (81 | ) |
| Commodity derivative transactions, net | | | (25 | ) | | | 33 | |
| Pension trust contribution | | | (157 | ) | | | — | |
| Asset impairments | | | 31 | | | | 12 | |
| Cash collateral paid | | | (28 | ) | | | (46 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 164 | | | | 2 | |
| Materials and supplies | | | 40 | | | | (42 | ) |
| Prepayments and other current assets | | | 118 | | | | 33 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (90 | ) | | | (57 | ) |
| Accrued taxes | | | (182 | ) | | | 7 | |
| Accrued interest | | | 76 | | | | 66 | |
| Other | | | 15 | | | | 19 | |
| | | | | | | |
| Net cash provided from operating activities | | | 491 | | | | 506 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New financing- | | | | | | | | |
| Long-term debt | | | 217 | | | | — | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (359 | ) | | | (109 | ) |
| Short-term borrowings, net | | | (214 | ) | | | (295 | ) |
| Common stock dividend payments | | | (190 | ) | | | (168 | ) |
| Other | | | (4 | ) | | | (22 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (550 | ) | | | (594 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (449 | ) | | | (508 | ) |
| Proceeds from asset sales | | | — | | | | 114 | |
| Sales of investment securities held in trusts | | | 969 | | | | 733 | |
| Purchases of investment securities held in trusts | | | (993 | ) | | | (755 | ) |
| Customer acquisition costs | | | (1 | ) | | | (101 | ) |
| Cash investments | | | 47 | | | | 49 | |
| Cash received in Allegheny merger | | | 590 | | | | — | |
| Other | | | (22 | ) | | | (8 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | 141 | | | | (476 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 82 | | | | (564 | ) |
| Cash and cash equivalents at beginning of period | | | 1,019 | | | | 874 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 1,101 | | | $ | 310 | |
| | | | | | | |
| | | | | | | | | |
SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | |
| Non-cash transaction: merger with Allegheny, common stock issued | | $ | 4,354 | | | $ | — | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
4
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales to non-affiliates | | $ | 1,044,490 | | | $ | 668,685 | |
| Electric sales to affiliates | | | 260,874 | | | | 607,302 | |
| Other | | | 85,724 | | | | 112,106 | |
| | | | | | | |
| Total revenues | | | 1,391,088 | | | | 1,388,093 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Fuel | | | 343,109 | | | | 328,221 | |
| Purchased power from affiliates | | | 68,743 | | | | 60,953 | |
| Purchased power from non-affiliates | | | 296,938 | | | | 450,216 | |
| Other operating expenses | | | 495,935 | | | | 304,510 | |
| Provision for depreciation | | | 68,452 | | | | 62,918 | |
| General taxes | | | 29,105 | | | | 26,746 | |
| Impairment of long-lived assets | | | 13,800 | | | | 1,833 | |
| | | | | | | |
| Total expenses | | | 1,316,082 | | | | 1,235,397 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 75,006 | | | | 152,696 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 5,861 | | | | 717 | |
| Miscellaneous income | | | 19,241 | | | | 3,143 | |
| Interest expense — affiliates | | | (1,017 | ) | | | (2,305 | ) |
| Interest expense — other | | | (52,960 | ) | | | (49,644 | ) |
| Capitalized interest | | | 9,919 | | | | 19,690 | |
| | | | | | | |
| Total other expense | | | (18,956 | ) | | | (28,399 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 56,050 | | | | 124,297 | |
| | | | | | | | | |
INCOME TAXES | | | 20,116 | | | | 44,371 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | | 35,934 | | | | 79,926 | |
| | | | | | | |
| | | | | | | | | |
| Loss attributable to noncontrolling interest | | | (76 | ) | | | — | |
| | | | | | | |
| | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 36,010 | | | $ | 79,926 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 35,934 | | | $ | 79,926 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 1,512 | | | | (9,834 | ) |
| Unrealized gain (loss) on derivative hedges | | | (8,879 | ) | | | 1,274 | |
| Change in unrealized gain on available-for-sale securities | | | 7,807 | | | | 5,028 | |
| | | | | | | |
| Other comprehensive income (loss) | | | 440 | | | | (3,532 | ) |
| Income tax benefit related to other comprehensive income | | | (2,362 | ) | | | (1,340 | ) |
| | | | | | | |
| Other comprehensive income (loss), net of tax | | | 2,802 | | | | (2,192 | ) |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | | 38,736 | | | | 77,734 | |
| | | | | | | | | |
COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | (76 | ) | | | — | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | | $ | 38,812 | | | $ | 77,734 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
5
FIRSTENERGY SOLUTIONS CORP.
| FIRSTENERGY CORP. | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In millions) | |
| ASSETS | | | | | | |
| | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 310 | | | $ | 874 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $36 million and $33 million, | | | | | |
| respectively, for uncollectible accounts) | | | 1,255 | | | | 1,244 | |
| Other (less accumulated provisions of $7 million for uncollectible accounts) | | | 140 | | | | 153 | |
| Materials and supplies, at average cost | | | 699 | | | | 647 | |
| Prepaid taxes | | | 236 | | | | 248 | |
| Other | | | 214 | | | | 154 | |
| | | | 2,854 | | | | 3,320 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 27,980 | | | | 27,826 | |
| Less - Accumulated provision for depreciation | | | 11,554 | | | | 11,397 | |
| | | | 16,426 | | | | 16,429 | |
| Construction work in progress | | | 2,931 | | | | 2,735 | |
| | | | 19,357 | | | | 19,164 | |
| INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 1,882 | | | | 1,859 | |
| Investments in lease obligation bonds | | | 495 | | | | 543 | |
| Other | | | 609 | | | | 621 | |
| | | | 2,986 | | | | 3,023 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 5,575 | | | | 5,575 | |
| Regulatory assets | | | 2,398 | | | | 2,356 | |
| Power purchase contract asset | | | 148 | | | | 200 | |
| Other | | | 760 | | | | 666 | |
| | | | 8,881 | | | | 8,797 | |
| | | $ | 34,078 | | | $ | 34,304 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,783 | | | $ | 1,834 | |
| Short-term borrowings | | | 886 | | | | 1,181 | |
| Accounts payable | | | 772 | | | | 829 | |
| Accrued taxes | | | 266 | | | | 314 | |
| Other | | | 1,179 | | | | 1,130 | |
| | | | 4,886 | | | | 5,288 | |
| 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 | | | 5,432 | | | | 5,448 | |
| Accumulated other comprehensive loss | | | (1,399 | ) | | | (1,415 | ) |
| Retained earnings | | | 4,482 | | | | 4,495 | |
| Total common stockholders' equity | | | 8,546 | | | | 8,559 | |
| Noncontrolling interest | | | (11 | ) | | | (2 | ) |
| Total equity | | | 8,535 | | | | 8,557 | |
| Long-term debt and other long-term obligations | | | 11,847 | | | | 11,908 | |
| | | | 20,382 | | | | 20,465 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 2,602 | | | | 2,468 | |
| Asset retirement obligations | | | 1,449 | | | | 1,425 | |
| Deferred gain on sale and leaseback transaction | | | 984 | | | | 993 | |
| Power purchase contract liability | | | 738 | | | | 643 | |
| Retirement benefits | | | 1,527 | | | | 1,534 | |
| Lease market valuation liability | | | 251 | | | | 262 | |
| Other | | | 1,259 | | | | 1,226 | |
| | | | 8,810 | | | | 8,551 | |
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 34,078 | | | $ | 34,304 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these | |
| financial statements. | | | | | | | | |
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 6,839 | | | $ | 9,281 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $18,636 in 2011 and $16,591 in 2010 | | | 388,951 | | | | 365,758 | |
| Associated companies | | | 533,280 | | | | 477,565 | |
| Other, net of allowances for uncollectible accounts of $6,702 in 2011 and $6,765 in 2010 | | | 86,711 | | | | 89,550 | |
| Notes receivable from associated companies | | | 478,418 | | | | 396,770 | |
| Materials and supplies, at average cost | | | 488,997 | | | | 545,342 | |
| Derivatives | | | 328,156 | | | | 181,660 | |
| Prepayments and other | | | 50,938 | | | | 60,171 | |
| | | | | | | |
| | | | 2,362,290 | | | | 2,126,097 | |
| | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 11,239,565 | | | | 11,321,318 | |
| Less — Accumulated provision for depreciation | | | 4,107,542 | | | | 4,024,280 | |
| | | | | | | |
| | | | 7,132,023 | | | | 7,297,038 | |
| Construction work in progress | | | 756,305 | | | | 1,062,744 | |
| Property, plant and equipment held for sale, net | | | 476,602 | | | | — | |
| | | | | | | |
| | | | 8,364,930 | | | | 8,359,782 | |
| | | | | | | |
INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 1,159,903 | | | | 1,145,846 | |
| Other | | | 9,744 | | | | 11,704 | |
| | | | | | | |
| | | | 1,169,647 | | | | 1,157,550 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Customer intangibles | | | 131,870 | | | | 133,968 | |
| Goodwill | | | 24,248 | | | | 24,248 | |
| Property taxes | | | 41,112 | | | | 41,112 | |
| Unamortized sale and leaseback costs | | | 90,803 | | | | 73,386 | |
| Derivatives | | | 211,223 | | | | 97,603 | |
| Other | | | 53,057 | | | | 48,689 | |
| | | | | | | |
| | | | 552,313 | | | | 419,006 | |
| | | | | | | |
| | | $ | 12,449,180 | | | $ | 12,062,435 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 986,863 | | | $ | 1,132,135 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 360,543 | | | | 11,561 | |
| Other | | | 661 | | | | — | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 499,936 | | | | 466,623 | |
| Other | | | 189,144 | | | | 241,191 | |
| Accrued taxes | | | 66,493 | | | | 70,129 | |
| Derivatives | | | 380,744 | | | | 266,411 | |
| Other | | | 224,525 | | | | 251,671 | |
| | | | | | | |
| | | | 2,708,909 | | | | 2,439,721 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, without par value, authorized 750 shares- 7 shares outstanding | | | 1,487,565 | | | | 1,490,082 | |
| Accumulated other comprehensive loss | | | (117,612 | ) | | | (120,414 | ) |
| Retained earnings | | | 2,454,587 | | | | 2,418,577 | |
| | | | | | | |
| Total common stockholders’ equity | | | 3,824,540 | | | | 3,788,245 | |
| Noncontrolling interest | | | 16 | | | | (504 | ) |
| | | | | | | |
| Total equity | | | 3,824,556 | | | | 3,787,741 | |
| Long-term debt and other long-term obligations | | | 3,144,997 | | | | 3,180,875 | |
| | | | | | | |
| | | | 6,969,553 | | | | 6,968,616 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | 950,726 | | | | 959,154 | |
| Accumulated deferred income taxes | | | 117,503 | | | | 57,595 | |
| Accumulated deferred investment tax credits | | | 53,181 | | | | 54,224 | |
| Asset retirement obligations | | | 866,643 | | | | 892,051 | |
| Retirement benefits | | | 289,285 | | | | 285,160 | |
| Property taxes | | | 41,112 | | | | 41,112 | |
| Lease market valuation liability | | | 205,366 | | | | 216,695 | |
| Derivatives | | | 168,409 | | | | 81,393 | |
| Other | | | 78,493 | | | | 66,714 | |
| | | | | | | |
| | | | 2,770,718 | | | | 2,654,098 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 12,449,180 | | | $ | 12,062,435 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
6
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 35,934 | | | $ | 79,926 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 68,452 | | | | 62,918 | |
| Nuclear fuel and lease amortization | | | 46,653 | | | | 42,118 | |
| Deferred rents and lease market valuation liability | | | (38,759 | ) | | | (40,869 | ) |
| Deferred income taxes and investment tax credits, net | | | 61,268 | | | | 37,773 | |
| Asset impairments | | | 18,791 | | | | 11,439 | |
| Commodity derivative transactions, net | | | (35,293 | ) | | | 32,900 | |
| Cash collateral paid | | | (27,063 | ) | | | (21,411 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | (76,069 | ) | | | (158,288 | ) |
| Materials and supplies | | | 60,633 | | | | (8,700 | ) |
| Prepayments and other current assets | | | 8,728 | | | | 13,516 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (18,734 | ) | | | (41,057 | ) |
| Accrued taxes | | | (3,164 | ) | | | (16,300 | ) |
| Accrued interest | | | (11,845 | ) | | | (14,930 | ) |
| Other | | | 4,093 | | | | 12,069 | |
| | | | | | | |
| Net cash provided from (used for) operating activities | | | 93,625 | | | | (8,896 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New financing- | | | | | | | | |
| Long-term debt | | | 150,190 | | | | — | |
| Short-term borrowings, net | | | 349,643 | | | | — | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (331,428 | ) | | | (1,278 | ) |
| Short-term borrowings, net | | | — | | | | (9,237 | ) |
| Other | | | (1,017 | ) | | | (731 | ) |
| | | | | | | |
| Net cash provided from (used for) financing activities | | | 167,388 | | | | (11,246 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (159,006 | ) | | | (301,603 | ) |
| Proceeds from asset sales | | | — | | | | 114,272 | |
| Sales of investment securities held in trusts | | | 215,620 | | | | 272,094 | |
| Purchases of investment securities held in trusts | | | (230,912 | ) | | | (284,888 | ) |
| Loans from (to) associated companies, net | | | (81,647 | ) | | | 321,680 | |
| Customer acquisition costs | | | (1,103 | ) | | | (100,615 | ) |
| Other | | | (6,407 | ) | | | (799 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (263,455 | ) | | | 20,141 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (2,442 | ) | | | (1 | ) |
| Cash and cash equivalents at beginning of period | | | 9,281 | | | | 12 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 6,839 | | | $ | 11 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
7
OHIO EDISON COMPANY
| FIRSTENERGY CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In millions) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net Income | | $ | 149 | | | $ | 115 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 193 | | | | 177 | |
| Amortization of regulatory assets | | | 212 | | | | 411 | |
| Deferral of new regulatory assets | | | - | | | | (93 | ) |
| Nuclear fuel and lease amortization | | | 41 | | | | 27 | |
| Deferred purchased power and other costs | | | (77 | ) | | | (62 | ) |
| Deferred income taxes and investment tax credits, net | | | 59 | | | | (28 | ) |
| Investment impairment | | | 10 | | | | 36 | |
| Deferred rents and lease market valuation liability | | | (17 | ) | | | (14 | ) |
| Stock-based compensation | | | (15 | ) | | | (13 | ) |
| Accrued compensation and retirement benefits | | | (81 | ) | | | (66 | ) |
| Commodity derivative transactions, net | | | 33 | | | | 16 | |
| Cash collateral paid | | | (46 | ) | | | (15 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 2 | | | | 46 | |
| Materials and supplies | | | (42 | ) | | | (7 | ) |
| Prepayments and other current assets | | | 33 | | | | (71 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (57 | ) | | | (90 | ) |
| Accrued taxes | | | 7 | | | | (51 | ) |
| Accrued interest | | | 66 | | | | 118 | |
| Other | | | 36 | | | | 26 | |
| Net cash provided from operating activities | | | 506 | | | | 462 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | - | | | | 700 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (109 | ) | | | (444 | ) |
| Short-term borrowings, net | | | (295 | ) | | | - | |
| Common stock dividend payments | | | (168 | ) | | | (168 | ) |
| Other | | | (22 | ) | | | (18 | ) |
| Net cash provided from (used for) financing activities | | | (594 | ) | | | 70 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (508 | ) | | | (654 | ) |
| Proceeds from asset sales | | | 114 | | | | 8 | |
| Sales of investment securities held in trusts | | | 733 | | | | 567 | |
| Purchases of investment securities held in trusts | | | (755 | ) | | | (584 | ) |
| Customer intangibles | | | (101 | ) | | | - | |
| Cash investments | | | 49 | | | | 17 | |
| Other | | | (8 | ) | | | (32 | ) |
| Net cash used for investing activities | | | (476 | ) | | | (678 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (564 | ) | | | (146 | ) |
| Cash and cash equivalents at beginning of period | | | 874 | | | | 545 | |
| Cash and cash equivalents at end of period | | $ | 310 | | | $ | 399 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
| | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 363,831 | | | $ | 479,925 | |
| Excise and gross receipts tax collections | | | 28,195 | | | | 28,475 | |
| | | | | | | |
| Total revenues | | | 392,026 | | | | 508,400 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 93,262 | | | | 153,677 | |
| Purchased power from non-affiliates | | | 60,379 | | | | 94,231 | |
| Other operating costs | | | 101,462 | | | | 88,855 | |
| Provision for depreciation | | | 21,876 | | | | 21,880 | |
| Amortization of regulatory assets, net | | | 774 | | | | 29,345 | |
| General taxes | | | 49,426 | | | | 47,492 | |
| | | | | | | |
| Total expenses | | | 327,179 | | | | 435,480 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 64,847 | | | | 72,920 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 4,308 | | | | 5,244 | |
| Miscellaneous income (expense) | | | 290 | | | | (292 | ) |
| Interest expense | | | (22,145 | ) | | | (22,310 | ) |
| Capitalized interest | | | 331 | | | | 208 | |
| | | | | | | |
| Total other expense | | | (17,216 | ) | | | (17,150 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 47,631 | | | | 55,770 | |
| | | | | | | | | |
INCOME TAXES | | | 17,491 | | | | 19,609 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | | 30,140 | | | | 36,161 | |
| | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | | | 116 | | | | 132 | |
| | | | | | | |
| | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 30,024 | | | $ | 36,029 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 30,140 | | | $ | 36,161 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 339 | | | | 4,015 | |
| Change in unrealized gain on available-for-sale securities | | | (22 | ) | | | 291 | |
| | | | | | | |
| Other comprehensive income | | | 317 | | | | 4,306 | |
| Income tax expense (benefit) related to other comprehensive income | | | (1,496 | ) | | | 693 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 1,813 | | | | 3,613 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | | 31,953 | | | | 39,774 | |
| | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 116 | | | | 132 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 31,837 | | | $ | 39,642 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
8
CONSOLIDATED BALANCE SHEETS
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 345,030 | | | $ | 420,489 | |
| Receivables- | | | | | | | | |
| Customers (net of allowance for uncollectible accounts of $3,774 in 2011 and $4,086 in 2010) | | | 158,146 | | | | 176,591 | |
| Associated companies | | | 74,125 | | | | 118,135 | |
| Other | | | 17,290 | | | | 12,232 | |
| Notes receivable from associated companies | | | 16,762 | | | | 16,957 | |
| Prepayments and other | | | 29,366 | | | | 6,393 | |
| | | | | | | |
| | | | 640,719 | | | | 750,797 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 3,156,648 | | | | 3,136,623 | |
| Less — Accumulated provision for depreciation | | | 1,217,827 | | | | 1,207,745 | |
| | | | | | | |
| | | | 1,938,821 | | | | 1,928,878 | |
| Construction work in progress | | | 48,302 | | | | 45,103 | |
| | | | | | | |
| | | | 1,987,123 | | | | 1,973,981 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lease obligation bonds | | | 190,340 | | | | 190,420 | |
| Nuclear plant decommissioning trusts | | | 126,826 | | | | 127,017 | |
| Other | | | 94,604 | | | | 95,563 | |
| | | | | | | |
| | | | 411,770 | | | | 413,000 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Regulatory assets | | | 385,005 | | | | 400,322 | |
| Pension assets | | | 59,104 | | | | 28,596 | |
| Property taxes | | | 71,331 | | | | 71,331 | |
| Unamortized sale and leaseback costs | | | 28,877 | | | | 30,126 | |
| Other | | | 16,007 | | | | 17,634 | |
| | | | | | | |
| | | | 560,324 | | | | 548,009 | |
| | | | | | | |
| | | $ | 3,599,936 | | | $ | 3,685,787 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,424 | | | $ | 1,419 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 103,071 | | | | 142,116 | |
| Other | | | 320 | | | | 320 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 96,003 | | | | 99,421 | |
| Other | | | 25,515 | | | | 29,639 | |
| Accrued taxes | | | 68,415 | | | | 78,707 | |
| Accrued interest | | | 25,334 | | | | 25,382 | |
| Other | | | 105,315 | | | | 74,947 | |
| | | | | | | |
| | | | 425,397 | | | | 451,951 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, without par value, authorized 175,000,000 shares- 60 shares outstanding | | | 951,802 | | | | 951,866 | |
| Accumulated other comprehensive loss | | | (177,263 | ) | | | (179,076 | ) |
| Retained earnings | | | 71,645 | | | | 141,621 | |
| | | | | | | |
| Total common stockholders’ equity | | | 846,184 | | | | 914,411 | |
| Noncontrolling interest | | | 5,796 | | | | 5,680 | |
| | | | | | | |
| Total equity | | | 851,980 | | | | 920,091 | |
| Long-term debt and other long-term obligations | | | 1,152,171 | | | | 1,152,134 | |
| | | | | | | |
| | | | 2,004,151 | | | | 2,072,225 | |
| | | | | | | |
| | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 719,979 | | | | 696,410 | |
| Accumulated deferred investment tax credits | | | 9,799 | | | | 10,159 | |
| Retirement benefits | | | 182,461 | | | | 183,712 | |
| Asset retirement obligations | | | 69,793 | | | | 74,456 | |
| Other | | | 188,356 | | | | 196,874 | |
| | | | | | | |
| | | | 1,170,388 | | | | 1,161,611 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 3,599,936 | | | $ | 3,685,787 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
9
OHIO EDISON COMPANY
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales to affiliates | | $ | 607,302 | | | $ | 892,690 | |
| Electric sales to non-affiliates | | | 668,685 | | | | 279,746 | |
| Other | | | 112,106 | | | | 53,670 | |
| Total revenues | | | 1,388,093 | | | | 1,226,106 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Fuel | | | 328,221 | | | | 306,158 | |
| Purchased power from affiliates | | | 60,953 | | | | 63,207 | |
| Purchased power from non-affiliates | | | 450,216 | | | | 160,342 | |
| Other operating expenses | | | 304,510 | | | | 307,356 | |
| Provision for depreciation | | | 62,918 | | | | 61,373 | |
| General taxes | | | 26,746 | | | | 23,376 | |
| Total expenses | | | 1,233,564 | | | | 921,812 | |
| | | | | | | | | |
| OPERATING INCOME | | | 154,529 | | | | 304,294 | |
| | | | | | | | | |
| OTHER EXPENSE: | | | | | | | | |
| Investment income (loss) | | | 717 | | | | (28,874 | ) |
| Miscellaneous expense | | | 1,310 | | | | 2,511 | |
| Interest expense to affiliates | | | (2,305 | ) | | | (2,979 | ) |
| Interest expense - other | | | (49,644 | ) | | | (22,527 | ) |
| Capitalized interest | | | 19,690 | | | | 10,078 | |
| Total other expense | | | (30,232 | ) | | | (41,791 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 124,297 | | | | 262,503 | |
| | | | | | | | | |
| INCOME TAXES | | | 44,371 | | | | 91,822 | |
| | | | | | | | | |
| NET INCOME | | | 79,926 | | | | 170,681 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | (9,834 | ) | | | 2,568 | |
| Unrealized gain on derivative hedges | | | 1,274 | | | | 11,016 | |
| Change in unrealized gain on available-for-sale securities | | | 5,028 | | | | (1,477 | ) |
| Other comprehensive income (loss) | | | (3,532 | ) | | | 12,107 | |
| Income tax expense (benefit) related to other comprehensive income | | | (1,340 | ) | | | 4,709 | |
| Other comprehensive income (loss), net of tax | | | (2,192 | ) | | | 7,398 | |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 77,734 | | | $ | 178,079 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 30,140 | | | $ | 36,161 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 21,876 | | | | 21,880 | |
| Amortization of regulatory assets, net | | | 774 | | | | 29,345 | |
| Purchased power cost recovery reconciliation | | | (4,926 | ) | | | (5,908 | ) |
| Amortization of lease costs | | | 32,933 | | | | 32,934 | |
| Deferred income taxes and investment tax credits, net | | | 26,682 | | | | (2,489 | ) |
| Accrued compensation and retirement benefits | | | (7,944 | ) | | | (12,160 | ) |
| Pension trust contribution | | | (27,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 82,291 | | | | 65,141 | |
| Prepayments and other current assets | | | (22,973 | ) | | | (21,802 | ) |
| Decrease in operating liabilities- | | | | | | | | |
| Accounts payable | | | (19,625 | ) | | | (35,461 | ) |
| Accrued taxes | | | (10,305 | ) | | | (15,849 | ) |
| Accrued interest | | | (48 | ) | | | (226 | ) |
| Other | | | 2,438 | | | | 9,647 | |
| | | | | | | |
| Net cash provided from operating activities | | | 104,313 | | | | 101,213 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (110 | ) | | | (1,363 | ) |
| Short-term borrowings, net | | | (39,045 | ) | | | (92,863 | ) |
| Common stock dividend payments | | | (100,000 | ) | | | (250,000 | ) |
| Other | | | — | | | | (113 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (139,155 | ) | | | (344,339 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (37,651 | ) | | | (35,680 | ) |
| Sales of investment securities held in trusts | | | 7,972 | | | | 2,424 | |
| Purchases of investment securities held in trusts | | | (8,896 | ) | | | (2,971 | ) |
| Loan repayments from associated companies, net | | | 195 | | | | 14,469 | |
| Cash investments | | | (136 | ) | | | (384 | ) |
| Other | | | (2,101 | ) | | | 1,773 | |
| | | | | | | |
| Net cash used for investing activities | | | (40,617 | ) | | | (20,369 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (75,459 | ) | | | (263,495 | ) |
| Cash and cash equivalents at beginning of period | | | 420,489 | | | | 324,175 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 345,030 | | | $ | 60,680 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
10
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 206,742 | | | $ | 312,497 | |
| Excise tax collections | | | 18,145 | | | | 17,573 | |
| | | | | | | |
| Total revenues | | | 224,887 | | | | 330,070 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 46,168 | | | | 109,393 | |
| Purchased power from non-affiliates | | | 18,220 | | | | 37,398 | |
| Other operating expenses | | | 35,036 | | | | 31,235 | |
| Provision for depreciation | | | 18,426 | | | | 18,111 | |
| Amortization of regulatory assets | | | 23,370 | | | | 45,139 | |
| General taxes | | | 40,212 | | | | 38,489 | |
| | | | | | | |
| Total expenses | | | 181,432 | | | | 279,765 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 43,455 | | | | 50,305 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 6,597 | | | | 7,547 | |
| Miscellaneous income | | | 636 | | | | 581 | |
| Interest expense | | | (33,078 | ) | | | (33,621 | ) |
| Capitalized interest | | | 27 | | | | 26 | |
| | | | | | | |
| Total other expense | | | (25,818 | ) | | | (25,467 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 17,637 | | | | 24,838 | |
| | | | | | | | | |
INCOME TAXES | | | 4,436 | | | | 10,843 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | | 13,201 | | | | 13,995 | |
| | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | | | 366 | | | | 419 | |
| | | | | | | |
| | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 12,835 | | | $ | 13,576 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 13,201 | | | $ | 13,995 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 2,967 | | | | (22,585 | ) |
| Income tax benefit related to other comprehensive income | | | (462 | ) | | | (8,277 | ) |
| | | | | | | |
| Other comprehensive income (loss), net of tax | | | 3,429 | | | | (14,308 | ) |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME (LOSS) | | | 16,630 | | | | (313 | ) |
| | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 366 | | | | 419 | |
| | | | | | | |
| | | | | | | | | |
TOTAL COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT | | $ | 16,264 | | | $ | (732 | ) |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
11
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 11 | | | $ | 12 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $13,641,000 and $12,041,000, | | | | | |
| respectively, for uncollectible accounts) | | | 248,994 | | | | 195,107 | |
| Associated companies | | | 360,804 | | | | 318,561 | |
| Other (less accumulated provisions of $6,702,000) | | | 81,659 | | | | 51,872 | |
| Notes receivable from associated companies | | | 483,423 | | | | 805,103 | |
| Materials and supplies, at average cost | | | 558,751 | | | | 539,541 | |
| Prepayments and other | | | 160,668 | | | | 107,782 | |
| | | | 1,894,310 | | | | 2,017,978 | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 10,368,007 | | | | 10,357,632 | |
| Less - Accumulated provision for depreciation | | | 4,617,864 | | | | 4,531,158 | |
| | | | 5,750,143 | | | | 5,826,474 | |
| Construction work in progress | | | 2,597,630 | | | | 2,423,446 | |
| | | | 8,347,773 | | | | 8,249,920 | |
| INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 1,091,114 | | | | 1,088,641 | |
| Other | | | 8,525 | | | | 22,466 | |
| | | | 1,099,639 | | | | 1,111,107 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Accumulated deferred income tax benefits | | | 66,462 | | | | 86,626 | |
| Goodwill | | | 24,248 | | | | 24,248 | |
| Customer intangibles | | | 114,567 | | | | 16,566 | |
| Property taxes | | | 50,125 | | | | 50,125 | |
| Unamortized sale and leaseback costs | | | 90,803 | | | | 72,553 | |
| Other | | | 109,494 | | | | 121,665 | |
| | | | 455,699 | | | | 371,783 | |
| | | $ | 11,797,421 | | | $ | 11,750,788 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,601,184 | | | $ | 1,550,927 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | - | | | | 9,237 | |
| Other | | | 100,000 | | | | 100,000 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 385,251 | | | | 466,078 | |
| Other | | | 270,457 | | | | 245,363 | |
| Accrued taxes | | | 66,585 | | | | 83,158 | |
| Other | | | 393,512 | | | | 359,057 | |
| | | | 2,816,989 | | | | 2,813,820 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity - | | | | | | | | |
| Common stock, without par value, authorized 750 shares, | | | | | | | | |
| 7 shares outstanding | | | 1,465,698 | | | | 1,468,423 | |
| Accumulated other comprehensive loss | | | (105,193 | ) | | | (103,001 | ) |
| Retained earnings | | | 2,229,075 | | | | 2,149,149 | |
| Total common stockholder's equity | | | 3,589,580 | | | | 3,514,571 | |
| Long-term debt and other long-term obligations | | | 2,660,200 | | | | 2,711,652 | |
| | | | 6,249,780 | | | | 6,226,223 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | 984,440 | | | | 992,869 | |
| Accumulated deferred investment tax credits | | | 57,353 | | | | 58,396 | |
| Asset retirement obligations | | | 936,453 | | | | 921,448 | |
| Retirement benefits | | | 219,174 | | | | 204,035 | |
| Property taxes | | | 50,125 | | | | 50,125 | |
| Lease market valuation liability | | | 250,871 | | | | 262,200 | |
| Other | | | 232,236 | | | | 221,672 | |
| | | | 2,730,652 | | | | 2,710,745 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 11,797,421 | | | $ | 11,750,788 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 30,244 | | | $ | 238 | |
| Receivables- | | | | | | | | |
| Customers (less allowance for doubtful accounts of $3,018 in 2011 and $4,589 in 2010, respectively) | | | 107,418 | | | | 183,744 | |
| Associated companies | | | 34,819 | | | | 77,047 | |
| Other | | | 4,848 | | | | 11,544 | |
| Notes receivable from associated companies | | | 22,704 | | | | 23,236 | |
| Prepayments and other | | | 13,894 | | | | 3,656 | |
| | | | | | | |
| | | | 213,927 | | | | 299,465 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,407,827 | | | | 2,396,893 | |
| Less — Accumulated provision for depreciation | | | 937,105 | | | | 932,246 | |
| | | | | | | |
| | | | 1,470,722 | | | | 1,464,647 | |
| Construction work in progress | | | 48,572 | | | | 38,610 | |
| | | | | | | |
| | | | 1,519,294 | | | | 1,503,257 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 286,747 | | | | 340,029 | |
| Other | | | 10,035 | | | | 10,074 | |
| | | | | | | |
| | | | 296,782 | | | | 350,103 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,688,521 | | | | 1,688,521 | |
| Regulatory assets | | | 337,189 | | | | 370,403 | |
| Property taxes | | | 80,614 | | | | 80,614 | |
| Other | | | 11,176 | | | | 11,486 | |
| | | | | | | |
| | | | 2,117,500 | | | | 2,151,024 | |
| | | | | | | |
| | | $ | 4,147,503 | | | $ | 4,303,849 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 174 | | | $ | 161 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 23,303 | | | | 105,996 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 43,564 | | | | 32,020 | |
| Other | | | 8,811 | | | | 14,947 | |
| Accrued taxes | | | 75,771 | | | | 84,668 | |
| Accrued interest | | | 39,256 | | | | 18,555 | |
| Other | | | 40,862 | | | | 44,569 | |
| | | | | | | |
| | | | 231,741 | | | | 300,916 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholder’s equity- | | | | | | | | |
| Common stock, without par value, authorized 105,000,000 shares- 67,930,743 shares outstanding | | | 886,995 | | | | 887,087 | |
| Accumulated other comprehensive loss | | | (149,758 | ) | | | (153,187 | ) |
| Retained earnings | | | 531,741 | | | | 568,906 | |
| | | | | | | |
| Total common stockholder’s equity | | | 1,268,978 | | | | 1,302,806 | |
| Noncontrolling interest | | | 14,886 | | | | 18,017 | |
| | | | | | | |
| Total equity | | | 1,283,864 | | | | 1,320,823 | |
| Long-term debt and other long-term obligations | | | 1,831,011 | | | | 1,852,530 | |
| | | | | | | |
| | | | 3,114,875 | | | | 3,173,353 | |
| | | | | | | |
| | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 631,507 | | | | 622,771 | |
| Accumulated deferred investment tax credits | | | 10,784 | | | | 10,994 | |
| Retirement benefits | | | 60,682 | | | | 95,654 | |
| Other | | | 97,914 | | | | 100,161 | |
| | | | | | | |
| | | | 800,887 | | | | 829,580 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 4,147,503 | | | $ | 4,303,849 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
12
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 13,201 | | | $ | 13,995 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 18,426 | | | | 18,111 | |
| Amortization of regulatory assets, net | | | 23,370 | | | | 45,139 | |
| Deferred income taxes and investment tax credits, net | | | 4,140 | | | | (13,627 | ) |
| Accrued compensation and retirement benefits | | | 2,158 | | | | 2,282 | |
| Accrued regulatory obligations | | | (863 | ) | | | (26 | ) |
| Pension trust contribution | | | (35,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 136,887 | | | | 70,633 | |
| Prepayments and other current assets | | | (10,236 | ) | | | (9,133 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 5,408 | | | | (14,387 | ) |
| Accrued taxes | | | (8,898 | ) | | | (16,616 | ) |
| Accrued interest | | | 20,701 | | | | 20,795 | |
| Other | | | (3,870 | ) | | | (2,636 | ) |
| | | | | | | |
| Net cash provided from operating activities | | | 165,424 | | | | 114,530 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (36 | ) | | | (26 | ) |
| Short-term borrowings, net | | | (104,228 | ) | | | (126,334 | ) |
| Common stock dividend payments | | | (50,000 | ) | | | (100,000 | ) |
| Other | | | (3,497 | ) | | | (3,365 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (157,761 | ) | | | (229,725 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (29,334 | ) | | | (19,735 | ) |
| Loans to associated companies, net | | | 532 | | | | 1,426 | |
| Redemptions of lessor notes | | | 53,282 | | | | 48,606 | |
| Other | | | (2,137 | ) | | | (1,085 | ) |
| | | | | | | |
| Net cash provided from investing activities | | | 22,343 | | | | 29,212 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 30,006 | | | | (85,983 | ) |
| Cash and cash equivalents at beginning of period | | | 238 | | | | 86,230 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 30,244 | | | $ | 247 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
13
THE TOLEDO EDISON COMPANY
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 79,926 | | | $ | 170,681 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 62,918 | | | | 61,373 | |
| Nuclear fuel and lease amortization | | | 42,118 | | | | 27,169 | |
| Deferred rents and lease market valuation liability | | | (40,869 | ) | | | (37,522 | ) |
| Deferred income taxes and investment tax credits, net | | | 37,773 | | | | 24,866 | |
| Investment impairment | | | 9,606 | | | | 33,535 | |
| Commodity derivative transactions, net | | | 32,900 | | | | 15,817 | |
| Cash collateral, net | | | (21,411 | ) | | | (5,492 | ) |
| Decrease (increase) in operating assets: | | | | | | | | |
| Receivables | | | (158,288 | ) | | | 80,067 | |
| Materials and supplies | | | (8,700 | ) | | | (865 | ) |
| Prepayments and other current assets | | | 13,516 | | | | (3,456 | ) |
| Increase (decrease) in operating liabilities: | | | | | | | | |
| Accounts payable | | | (41,057 | ) | | | (61,419 | ) |
| Accrued taxes | | | (16,300 | ) | | | 39,846 | |
| Accrued interest | | | (14,930 | ) | | | 10,338 | |
| Other | | | 13,902 | | | | (7,071 | ) |
| Net cash provided from (used for) operating activities | | | (8,896 | ) | | | 347,867 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | - | | | | 100,000 | |
| Short-term borrowings, net | | | - | | | | 621,294 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (1,278 | ) | | | (335,916 | ) |
| Short-term borrowings, net | | | (9,237 | ) | | | - | |
| Other | | | (731 | ) | | | - | |
| Net cash provided from (used for) financing activities | | | (11,246 | ) | | | 385,378 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (301,603 | ) | | | (412,805 | ) |
| Proceeds from asset sales | | | 114,272 | | | | 7,573 | |
| Sales of investment securities held in trusts | | | 272,094 | | | | 351,414 | |
| Purchases of investment securities held in trusts | | | (284,888 | ) | | | (356,904 | ) |
| Loans from (to) associated companies, net | | | 321,680 | | | | (303,963 | ) |
| Customer intangibles | | | (100,615 | ) | | | - | |
| Other | | | (799 | ) | | | (18,565 | ) |
| Net cash provided from (used for) investing activities | | | 20,141 | | | | (733,250 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (1 | ) | | | (5 | ) |
| Cash and cash equivalents at beginning of period | | | 12 | | | | 39 | |
| Cash and cash equivalents at end of period | | $ | 11 | | | $ | 34 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
| | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 106,325 | | | $ | 125,431 | |
| Excise tax collections | | | 7,302 | | | | 7,041 | |
| | | | | | | |
| Total revenues | | | 113,627 | | | | 132,472 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 35,517 | | | | 54,618 | |
| Purchased power from non-affiliates | | | 13,988 | | | | 18,491 | |
| Other operating expenses | | | 36,587 | | | | 25,545 | |
| Provision for depreciation | | | 7,931 | | | | 7,950 | |
| Deferral of regulatory assets, net | | | (11,478 | ) | | | (8,499 | ) |
| General taxes | | | 14,452 | | | | 13,461 | |
| | | | | | | |
| Total expenses | | | 96,997 | | | | 111,566 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 16,630 | | | | 20,906 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 2,922 | | | | 3,800 | |
| Miscellaneous expense | | | (1,629 | ) | | | (1,406 | ) |
| Interest expense | | | (10,443 | ) | | | (10,487 | ) |
| Capitalized interest | | | 102 | | | | 78 | |
| | | | | | | |
| Total other expense | | | (9,048 | ) | | | (8,015 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 7,582 | | | | 12,891 | |
| | | | | | | | | |
INCOME TAXES | | | 1,735 | | | | 5,382 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | | 5,847 | | | | 7,509 | |
| | | | | | | |
| | | | | | | | | |
| Income attributable to noncontrolling interest | | | 2 | | | | 3 | |
| | | | | | | |
| | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 5,845 | | | $ | 7,506 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 5,847 | | | $ | 7,509 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 592 | | | | 296 | |
| Change in unrealized gain on available-for-sale securities | | | 1,305 | | | | 369 | |
| | | | | | | |
| Other comprehensive income | | | 1,897 | | | | 665 | |
| Income tax expense related to other comprehensive income | | | 334 | | | | 170 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 1,563 | | | | 495 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | | 7,410 | | | | 8,004 | |
| | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 2 | | | | 3 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 7,408 | | | $ | 8,001 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
14
THE TOLEDO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 150,014 | | | $ | 149,262 | |
| Receivables- | | | | | | | | |
| Customers (net of allowance for uncollectible accounts of $1,209 in 2011 and $1 in 2010) | | | 45,749 | | | | 29 | |
| Associated companies | | | 56,913 | | | | 31,777 | |
| Other (net of allowance for uncollectible accounts of $343 in 2011 and $330 in 2010) | | | 18,752 | | | | 18,464 | |
| Notes receivable from associated companies | | | 35,489 | | | | 96,765 | |
| Prepayments and other | | | 8,302 | | | | 2,306 | |
| | | | | | | |
| | | | 315,219 | | | | 298,603 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 952,874 | | | | 947,203 | |
| Less — Accumulated provision for depreciation | | | 449,791 | | | | 446,401 | |
| | | | | | | |
| | | | 503,083 | | | | 500,802 | |
| Construction work in progress | | | 12,647 | | | | 12,604 | |
| | | | | | | |
| | | | 515,730 | | | | 513,406 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 82,133 | | | | 103,872 | |
| Nuclear plant decommissioning trusts | | | 77,141 | | | | 75,558 | |
| Other | | | 1,469 | | | | 1,492 | |
| | | | | | | |
| | | | 160,743 | | | | 180,922 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 500,576 | | | | 500,576 | |
| Regulatory assets | | | 83,544 | | | | 72,059 | |
| Pension assets | | | 24,427 | | | | — | |
| Property taxes | | | 24,990 | | | | 24,990 | |
| Other | | | 36,167 | | | | 23,750 | |
| | | | | | | |
| | | | 669,704 | | | | 621,375 | |
| | | | | | | |
| | | $ | 1,661,396 | | | $ | 1,614,306 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 191 | | | $ | 199 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 36,055 | | | | 17,168 | |
| Other | | | 5,238 | | | | 7,351 | |
| Accrued taxes | | | 23,043 | | | | 24,401 | |
| Accrued interest | | | 15,983 | | | | 5,931 | |
| Lease market valuation liability | | | 36,900 | | | | 36,900 | |
| Other | | | 54,905 | | | | 23,145 | |
| | | | | | | |
| | | | 172,315 | | | | 115,095 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, $5 par value, authorized 60,000,000 shares- 29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
| Other paid-in capital | | | 178,122 | | | | 178,182 | |
| Accumulated other comprehensive loss | | | (47,620 | ) | | | (49,183 | ) |
| Retained earnings | | | 108,379 | | | | 117,534 | |
| | | | | | | |
| Total common stockholders’ equity | | | 385,891 | | | | 393,543 | |
| Noncontrolling interest | | | 2,591 | | | | 2,589 | |
| | | | | | | |
| Total equity | | | 388,482 | | | | 396,132 | |
| Long-term debt and other long-term obligations | | | 600,508 | | | | 600,493 | |
| | | | | | | |
| | | | 988,990 | | | | 996,625 | |
| | | | | | | |
| | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 157,797 | | | | 132,019 | |
| Accumulated deferred investment tax credits | | | 5,822 | | | | 5,930 | |
| Retirement benefits | | | 51,253 | | | | 71,486 | |
| Asset retirement obligations | | | 29,245 | | | | 28,762 | |
| Lease market valuation liability | | | 190,075 | | | | 199,300 | |
| Other | | | 65,899 | | | | 65,089 | |
| | | | | | | |
| | | | 500,091 | | | | 502,586 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 1,661,396 | | | $ | 1,614,306 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
15
THE TOLEDO EDISON COMPANY
| OHIO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 479,925 | | | $ | 720,011 | |
| Excise and gross receipts tax collections | | | 28,475 | | | | 28,980 | |
| Total revenues | | | 508,400 | | | | 748,991 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 135,857 | | | | 332,336 | |
| Purchased power from non-affiliates | | | 112,051 | | | | 137,813 | |
| Other operating costs | | | 88,855 | | | | 157,830 | |
| Provision for depreciation | | | 21,880 | | | | 21,513 | |
| Amortization of regulatory assets, net | | | 29,345 | | | | 20,211 | |
| General taxes | | | 47,492 | | | | 49,120 | |
| Total expenses | | | 435,480 | | | | 718,823 | |
| | | | | | | | | |
| OPERATING INCOME | | | 72,920 | | | | 30,168 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 5,244 | | | | 9,362 | |
| Miscellaneous expense | | | (292 | ) | | | (810 | ) |
| Interest expense | | | (22,310 | ) | | | (23,287 | ) |
| Capitalized interest | | | 208 | | | | 220 | |
| Total other expense | | | (17,150 | ) | | | (14,515 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 55,770 | | | | 15,653 | |
| | | | | | | | | |
| INCOME TAXES | | | 19,609 | | | | 4,005 | |
| | | | | | | | | |
| NET INCOME | | | 36,161 | | | | 11,648 | |
| | | | | | | | | |
| Noncontrolling interest income | | | 132 | | | | 146 | |
| | | | | | | | | |
| EARNINGS AVAILABLE TO PARENT | | $ | 36,029 | | | $ | 11,502 | |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 36,161 | | | $ | 11,648 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 4,015 | | | | 5,738 | |
| Change in unrealized gain on available-for-sale securities | | | 291 | | | | (2,709 | ) |
| Other comprehensive income | | | 4,306 | | | | 3,029 | |
| Income tax expense related to other comprehensive income | | | 693 | | | | 529 | |
| Other comprehensive income, net of tax | | | 3,613 | | | | 2,500 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | | 39,774 | | | | 14,148 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 132 | | | | 146 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 39,642 | | | $ | 14,002 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 5,847 | | | $ | 7,509 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 7,931 | | | | 7,950 | |
| Deferral of regulatory assets, net | | | (11,478 | ) | | | (8,499 | ) |
| Deferred rents and lease market valuation liability | | | 6,141 | | | | 6,141 | |
| Deferred income taxes and investment tax credits, net | | | 25,046 | | | | 11,287 | |
| Accrued compensation and retirement benefits | | | (142 | ) | | | 837 | |
| Pension trust contribution | | | (45,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | (70,694 | ) | | | 45,376 | |
| Prepayments and other current assets | | | (5,996 | ) | | | (4,569 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 16,774 | | | | (35,414 | ) |
| Accrued taxes | | | (1,358 | ) | | | (4,933 | ) |
| Accrued interest | | | 10,052 | | | | 10,050 | |
| Other | | | 6,098 | | | | (4,578 | ) |
| | | | | | | |
| Net cash provided from (used for) operating activities | | | (56,779 | ) | | | 31,157 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (56 | ) | | | (56 | ) |
| Short-term borrowings, net | | | — | | | | (225,975 | ) |
| Common stock dividend payments | | | (15,000 | ) | | | (130,000 | ) |
| Other | | | — | | | | (2 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (15,056 | ) | | | (356,033 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (9,507 | ) | | | (9,597 | ) |
| Loan repayments from (loans to) associated companies, net | | | 61,276 | | | | (33,587 | ) |
| Redemptions of lessor notes | | | 21,739 | | | | 20,509 | |
| Sales of investment securities held in trusts | | | 13,883 | | | | 31,067 | |
| Purchases of investment securities held in trusts | | | (14,338 | ) | | | (31,705 | ) |
| Other | | | (466 | ) | | | (1,227 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | 72,587 | | | | (24,540 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 752 | | | | (349,416 | ) |
| Cash and cash equivalents at beginning of period | | | 149,262 | | | | 436,712 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 150,014 | | | $ | 87,296 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
16
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 634,023 | | | $ | 691,392 | |
| Excise tax collections | | | 12,487 | | | | 12,352 | |
| | | | | | | |
| Total revenues | | | 646,510 | | | | 703,744 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power | | | 370,168 | | | | 414,016 | |
| Other operating expenses | | | 86,079 | | | | 95,660 | |
| Provision for depreciation | | | 25,314 | | | | 27,971 | |
| Amortization of regulatory assets, net | | | 81,587 | | | | 69,448 | |
| General taxes | | | 17,411 | | | | 16,436 | |
| | | | | | | |
| Total expenses | | | 580,559 | | | | 623,531 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 65,951 | | | | 80,213 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income | | | 1,910 | | | | 1,833 | |
| Interest expense | | | (30,657 | ) | | | (29,423 | ) |
| Capitalized interest | | | 427 | | | | 133 | |
| | | | | | | |
| Total other expense | | | (28,320 | ) | | | (27,457 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 37,631 | | | | 52,756 | |
| | | | | | | | | |
INCOME TAXES | | | 18,078 | | | | 23,530 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 19,553 | | | $ | 29,226 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 19,553 | | | $ | 29,226 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 4,221 | | | | 15,928 | |
| Unrealized gain on derivative hedges | | | 69 | | | | 69 | |
| | | | | | | |
| Other comprehensive income | | | 4,290 | | | | 15,997 | |
| Income tax expense related to other comprehensive income | | | 1,590 | | | | 6,558 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 2,700 | | | | 9,439 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 22,253 | | | $ | 38,665 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
17
JERSEY CENTRAL POWER & LIGHT COMPANY
| OHIO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 60,680 | | | $ | 324,175 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $5,417,000 and $5,119,000, respectively, | | | | | |
| for uncollectible accounts) | | | 196,226 | | | | 209,384 | |
| Associated companies | | | 49,839 | | | | 98,874 | |
| Other (less accumulated provisions of $1,000 and $18,000, respectively, | | | | | | | | |
| for uncollectible accounts) | | | 18,758 | | | | 14,155 | |
| Notes receivable from associated companies | | | 104,183 | | | | 118,651 | |
| Prepayments and other | | | 37,766 | | | | 15,964 | |
| | | | 467,452 | | | | 781,203 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 3,057,995 | | | | 3,036,467 | |
| Less - Accumulated provision for depreciation | | | 1,177,211 | | | | 1,165,394 | |
| | | | 1,880,784 | | | | 1,871,073 | |
| Construction work in progress | | | 35,331 | | | | 31,171 | |
| | | | 1,916,115 | | | | 1,902,244 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lease obligation bonds | | | 216,498 | | | | 216,600 | |
| Nuclear plant decommissioning trusts | | | 120,819 | | | | 120,812 | |
| Other | | | 96,669 | | | | 96,861 | |
| | | | 433,986 | | | | 434,273 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Regulatory assets | | | 432,526 | | | | 465,331 | |
| Pension assets | | | 33,128 | | | | 19,881 | |
| Property taxes | | | 67,037 | | | | 67,037 | |
| Unamortized sale and leaseback costs | | | 33,877 | | | | 35,127 | |
| Other | | | 36,454 | | | | 39,881 | |
| | | | 603,022 | | | | 627,257 | |
| | | $ | 3,420,575 | | | $ | 3,744,977 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,470 | | | $ | 2,723 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | - | | | | 92,863 | |
| Other | | | 807 | | | | 807 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 75,374 | | | | 102,763 | |
| Other | | | 32,351 | | | | 40,423 | |
| Accrued taxes | | | 66,100 | | | | 81,868 | |
| Accrued interest | | | 25,523 | | | | 25,749 | |
| Other | | | 109,429 | | | | 81,424 | |
| | | | 311,054 | | | | 428,620 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | |
| 60 shares outstanding | | | 949,735 | | | | 1,154,797 | |
| Accumulated other comprehensive loss | | | (159,964 | ) | | | (163,577 | ) |
| Retained earnings | | | 20,920 | | | | 29,890 | |
| Total common stockholder's equity | | | 810,691 | | | | 1,021,110 | |
| Noncontrolling interest | | | 6,574 | | | | 6,442 | |
| Total equity | | | 817,265 | | | | 1,027,552 | |
| Long-term debt and other long-term obligations | | | 1,160,250 | | | | 1,160,208 | |
| | | | 1,977,515 | | | | 2,187,760 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 670,758 | | | | 660,114 | |
| Accumulated deferred investment tax credits | | | 11,243 | | | | 11,406 | |
| Asset retirement obligations | | | 87,315 | | | | 85,926 | |
| Retirement benefits | | | 174,404 | | | | 174,925 | |
| Other | | | 188,286 | | | | 196,226 | |
| | | | 1,132,006 | | | | 1,128,597 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 3,420,575 | | | $ | 3,744,977 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 1 | | | $ | 4 | |
| Receivables- | | | | | | | | |
| Customers (net of allowance for uncollectible accounts of $3,842 in 2011 and $3,769 in 2010) | | | 268,171 | | | | 323,044 | |
| Associated companies | | | 27,144 | | | | 53,780 | |
| Other | | | 21,269 | | | | 26,119 | |
| Notes receivable — associated companies | | | 298,274 | | | | 177,228 | |
| Prepaid taxes | | | 10,968 | | | | 10,889 | |
| Other | | | 16,357 | | | | 12,654 | |
| | | | | | | |
| | | | 642,184 | | | | 603,718 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 4,579,753 | | | | 4,562,781 | |
| Less — Accumulated provision for depreciation | | | 1,667,017 | | | | 1,656,939 | |
| | | | | | | |
| | | | 2,912,736 | | | | 2,905,842 | |
| Construction work in progress | | | 78,819 | | | | 63,535 | |
| | | | | | | |
| | | | 2,991,555 | | | | 2,969,377 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear fuel disposal trust | | | 206,833 | | | | 207,561 | |
| Nuclear plant decommissioning trusts | | | 190,424 | | | | 181,851 | |
| Other | | | 2,111 | | | | 2,104 | |
| | | | | | | |
| | | | 399,368 | | | | 391,516 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,810,936 | | | | 1,810,936 | |
| Regulatory assets | | | 460,156 | | | | 513,395 | |
| Other | | | 25,243 | | | | 27,938 | |
| | | | | | | |
| | | | 2,296,335 | | | | 2,352,269 | |
| | | | | | | |
| | | $ | 6,329,442 | | | $ | 6,316,880 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 32,855 | | | $ | 32,402 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 16,983 | | | | 28,571 | |
| Other | | | 123,814 | | | | 158,442 | |
| Accrued compensation and benefits | | | 33,415 | | | | 35,232 | |
| Customer deposits | | | 23,494 | | | | 23,385 | |
| Accrued taxes | | | 15,142 | | | | 2,509 | |
| Accrued interest | | | 29,926 | | | | 18,111 | |
| Other | | | 25,663 | | | | 22,263 | |
| | | | | | | |
| | | | 301,292 | | | | 320,915 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, $10 par value, authorized 16,000,000 shares- 13,628,447 shares outstanding | | | 136,284 | | | | 136,284 | |
| Other paid-in capital | | | 2,508,754 | | | | 2,508,874 | |
| Accumulated other comprehensive loss | | | (250,842 | ) | | | (253,542 | ) |
| Retained earnings | | | 246,723 | | | | 227,170 | |
| | | | | | | |
| Total common stockholder’s equity | | | 2,640,919 | | | | 2,618,786 | |
| Long-term debt and other long-term obligations | | | 1,762,365 | | | | 1,769,849 | |
| | | | | | | |
| | | | 4,403,284 | | | | 4,388,635 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 729,478 | | | | 715,527 | |
| Power purchase contract liability | | | 238,677 | | | | 233,492 | |
| Nuclear fuel disposal costs | | | 196,843 | | | | 196,768 | |
| Retirement benefits | | | 175,175 | | | | 182,364 | |
| Asset retirement obligations | | | 110,050 | | | | 108,297 | |
| Other | | | 174,643 | | | | 170,882 | |
| | | | | | | |
| | | | 1,624,866 | | | | 1,607,330 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 6,329,442 | | | $ | 6,316,880 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
18
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 19,553 | | | $ | 29,226 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 25,314 | | | | 27,971 | |
| Amortization of regulatory assets, net | | | 81,587 | | | | 69,448 | |
| Deferred purchased power and other costs | | | (26,516 | ) | | | (32,775 | ) |
| Deferred income taxes and investment tax credits, net | | | 25,560 | | | | (2,082 | ) |
| Accrued compensation and retirement benefits | | | (4,776 | ) | | | (5,847 | ) |
| Cash collateral returned to suppliers | | | (250 | ) | | | (23,400 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 86,359 | | | | 33,257 | |
| Prepayments and other current assets | | | (1,687 | ) | | | 16,472 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (61,612 | ) | | | (40,992 | ) |
| Accrued taxes | | | 12,631 | | | | 50,857 | |
| Accrued interest | | | 11,815 | | | | 11,816 | |
| Tax collections payable | | | 7,084 | | | | 14,544 | |
| Other | | | 7,448 | | | | 466 | |
| | | | | | | |
| Net cash provided from operating activities | | | 182,510 | | | | 148,961 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (7,190 | ) | | | (6,773 | ) |
| Common stock dividend payments | | | — | | | | (90,000 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (7,190 | ) | | | (96,773 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (47,604 | ) | | | (37,338 | ) |
| Loans to associated companies, net | | | (121,046 | ) | | | (7,620 | ) |
| Sales of investment securities held in trusts | | | 217,103 | | | | 190,198 | |
| Purchases of investment securities held in trusts | | | (221,695 | ) | | | (194,748 | ) |
| Other | | | (2,081 | ) | | | (2,706 | ) |
| | | | | | | |
| Net cash used for investing activities | | | (175,323 | ) | | | (52,214 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (3 | ) | | | (26 | ) |
| Cash and cash equivalents at beginning of period | | | 4 | | | | 27 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 1 | | | $ | 1 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
19
METROPOLITAN EDISON COMPANY
| OHIO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 36,161 | | | $ | 11,648 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 21,880 | | | | 21,513 | |
| Amortization of regulatory assets, net | | | 29,345 | | | | 20,211 | |
| Purchased power cost recovery reconciliation | | | (5,908 | ) | | | 2,978 | |
| Amortization of lease costs | | | 32,934 | | | | 32,934 | |
| Deferred income taxes and investment tax credits, net | | | (2,489 | ) | | | (7,272 | ) |
| Accrued compensation and retirement benefits | | | (12,160 | ) | | | (1,746 | ) |
| Accrued regulatory obligations | | | (623 | ) | | | 18,350 | �� |
| Electric service prepayment programs | | | - | | | | (3,944 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 65,141 | | | | 1,435 | |
| Prepayments and other current assets | | | (21,802 | ) | | | (9,806 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (35,461 | ) | | | 11,880 | |
| Accrued taxes | | | (15,849 | ) | | | (26,222 | ) |
| Accrued interest | | | (226 | ) | | | (1,956 | ) |
| Other | | | 10,270 | | | | 6,708 | |
| Net cash provided from operating activities | | | 101,213 | | | | 76,711 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | - | | | | 79,810 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (1,363 | ) | | | (100,393 | ) |
| Short-term borrowings, net | | | (92,863 | ) | | | | |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (250,000 | ) | | | - | |
| Other | | | (113 | ) | | | (69 | ) |
| Net cash used for financing activities | | | (344,339 | ) | | | (20,652 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (35,680 | ) | | | (37,523 | ) |
| Sales of investment securities held in trusts | | | 2,424 | | | | 9,417 | |
| Purchases of investment securities held in trusts | | | (2,971 | ) | | | (10,422 | ) |
| Loan repayments from associated companies, net | | | 14,469 | | | | 146,098 | |
| Cash investments | | | (384 | ) | | | (243 | ) |
| Other | | | 1,773 | | | | 1,463 | |
| Net cash provided from (used for) investing activities | | | (20,369 | ) | | | 108,790 | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (263,495 | ) | | | 164,849 | |
| Cash and cash equivalents at beginning of period | | | 324,175 | | | | 146,343 | |
| Cash and cash equivalents at end of period | | $ | 60,680 | | | $ | 311,192 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
| | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 338,416 | | | $ | 451,560 | |
| Gross receipts tax collections | | | 18,800 | | | | 21,567 | |
| | | | | | | |
| Total revenues | | | 357,216 | | | | 473,127 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 49,889 | | | | 161,080 | |
| Purchased power from non-affiliates | | | 153,043 | | | | 91,928 | |
| Other operating expenses | | | 47,232 | | | | 101,983 | |
| Provision for depreciation | | | 12,423 | | | | 12,758 | |
| Amortization of regulatory assets, net | | | 32,094 | | | | 48,800 | |
| General taxes | | | 22,150 | | | | 21,740 | |
| | | | | | | |
| Total expenses | | | 316,831 | | | | 438,289 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 40,385 | | | | 34,838 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Interest income | | | 93 | | | | 1,217 | |
| Miscellaneous income | | | 970 | | | | 2,173 | |
| Interest expense | | | (13,057 | ) | | | (13,773 | ) |
| Capitalized interest | | | 147 | | | | 126 | |
| | | | | | | |
| Total other expense | | | (11,847 | ) | | | (10,257 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 28,538 | | | | 24,581 | |
| | | | | | | | | |
INCOME TAXES | | | 5,951 | | | | 12,266 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 22,587 | | | $ | 12,315 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 22,587 | | | $ | 12,315 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 1,963 | | | | 9,709 | |
| Unrealized gain on derivative hedges | | | 84 | | | | 84 | |
| | | | | | | |
| Other comprehensive income | | | 2,047 | | | | 9,793 | |
| Income tax expense related to other comprehensive income | | | 763 | | | | 4,177 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 1,284 | | | | 5,616 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 23,871 | | | $ | 17,931 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
20
METROPOLITAN EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 117 | | | $ | 243,220 | |
| Receivables- | | | | | | | | |
| Customers (less allowance for doubtful accounts of $3,841 in 2011 and $3,868 in 2010, respectively) | | | 159,801 | | | | 178,522 | |
| Associated companies | | | 23,110 | | | | 24,920 | |
| Other | | | 16,836 | | | | 13,007 | |
| Notes receivable from associated companies | | | 9,542 | | | | 11,028 | |
| Prepaid taxes | | | 40,883 | | | | 343 | |
| Other | | | 1,973 | | | | 2,289 | |
| | | | | | | |
| | | | 252,262 | | | | 473,329 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,260,156 | | | | 2,247,853 | |
| Less — Accumulated provision for depreciation | | | 852,326 | | | | 846,003 | |
| | | | | | | |
| | | | 1,407,830 | | | | 1,401,850 | |
| Construction work in progress | | | 27,714 | | | | 23,663 | |
| | | | | | | |
| | | | 1,435,544 | | | | 1,425,513 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 303,906 | | | | 289,328 | |
| Other | | | 881 | | | | 884 | |
| | | | | | | |
| | | | 304,787 | | | | 290,212 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 416,499 | | | | 416,499 | |
| Regulatory assets | | | 285,300 | | | | 295,856 | |
| Power purchase contract asset | | | 107,055 | | | | 111,562 | |
| Other | | | 51,939 | | | | 31,699 | |
| | | | | | | |
| | | | 860,793 | | | | 855,616 | |
| | | | | | | |
| | | $ | 2,853,386 | | | $ | 3,044,670 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 42,450 | | | $ | 28,760 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 109,709 | | | | 124,079 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 35,758 | | | | 33,942 | |
| Other | | | 47,450 | | | | 29,862 | |
| Accrued taxes | | | 14,514 | | | | 60,856 | |
| Accrued interest | | | 11,738 | | | | 16,114 | |
| Other | | | 29,543 | | | | 29,278 | |
| | | | | | | |
| | | | 291,162 | | | | 322,891 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, without par value, authorized 900,000 shares- 740,905 shares outstanding | | | 1,046,970 | | | | 1,197,076 | |
| Accumulated other comprehensive loss | | | (141,099 | ) | | | (142,383 | ) |
| Retained earnings | | | 29,994 | | | | 32,406 | |
| | | | | | | |
| Total common stockholder’s equity | | | 935,865 | | | | 1,087,099 | |
| Long-term debt and other long-term obligations | | | 705,125 | | | | 718,860 | |
| | | | | | | |
| | | | 1,640,990 | | | | 1,805,959 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 481,530 | | | | 473,009 | |
| Accumulated deferred investment tax credits | | | 6,761 | | | | 6,866 | |
| Nuclear fuel disposal costs | | | 44,465 | | | | 44,449 | |
| Asset retirement obligations | | | 195,883 | | | | 192,659 | |
| Retirement benefits | | | 22,405 | | | | 29,121 | |
| Power purchase contract liability | | | 118,123 | | | | 116,027 | |
| Other | | | 52,067 | | | | 53,689 | |
| | | | | | | |
| | | | 921,234 | | | | 915,820 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 2,853,386 | | | $ | 3,044,670 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
21
METROPOLITAN EDISON COMPANY
| THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS) | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 312,497 | | | $ | 431,405 | |
| Excise tax collections | | | 17,573 | | | | 18,320 | |
| Total revenues | | | 330,070 | | | | 449,725 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 94,965 | | | | 238,872 | |
| Purchased power from non-affiliates | | | 51,826 | | | | 71,746 | |
| Other operating costs | | | 31,235 | | | | 64,830 | |
| Provision for depreciation | | | 18,111 | | | | 18,280 | |
| Amortization of regulatory assets | | | 45,139 | | | | 256,737 | |
| Deferral of new regulatory assets | | | - | | | | (94,816 | ) |
| General taxes | | | 38,489 | | | | 38,141 | |
| Total expenses | | | 279,765 | | | | 593,790 | |
| | | | | | | | | |
| OPERATING INCOME (LOSS) | | | 50,305 | | | | (144,065 | ) |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 7,547 | | | | 8,420 | |
| Miscellaneous income | | | 581 | | | | 1,994 | |
| Interest expense | | | (33,621 | ) | | | (33,322 | ) |
| Capitalized interest | | | 26 | | | | 67 | |
| Total other expense | | | (25,467 | ) | | | (22,841 | ) |
| | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | | 24,838 | | | | (166,906 | ) |
| | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT) | | | 10,843 | | | | (61,506 | ) |
| | | | | | | | | |
| NET INCOME (LOSS) | | | 13,995 | | | | (105,400 | ) |
| | | | | | | | | |
| Noncontrolling interest income | | | 419 | | | | 458 | |
| | | | | | | | | |
| EARNINGS (LOSS) AVAILABLE TO PARENT | | $ | 13,576 | | | $ | (105,858 | ) |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME (LOSS) | | $ | 13,995 | | | $ | (105,400 | ) |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | (22,585 | ) | | | 3,967 | |
| Income tax expense (benefit) related to other comprehensive income | | | (8,277 | ) | | | 1,370 | |
| Other comprehensive income (loss), net of tax | | | (14,308 | ) | | | 2,597 | |
| | | | | | | | | |
| COMPREHENSIVE LOSS | | | (313 | ) | | | (102,803 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 419 | | | | 458 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT | | $ | (732 | ) | | $ | (103,261 | ) |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 22,587 | | | $ | 12,315 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 12,423 | | | | 12,758 | |
| Amortization of regulatory assets, net | | | 32,094 | | | | 48,800 | |
| Deferred costs recoverable as regulatory assets | | | (12,082 | ) | | | (18,276 | ) |
| Deferred income taxes and investment tax credits, net | | | 1,304 | | | | (10,308 | ) |
| Accrued compensation and retirement benefits | | | (1,433 | ) | | | (2,527 | ) |
| Cash collateral returned from (paid to) suppliers | | | 1,000 | | | | (700 | ) |
| Pension trust contributions | | | (35,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 16,702 | | | | (5,083 | ) |
| Prepayments and other current assets | | | (40,225 | ) | | | (52,040 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 15,749 | | | | (7,279 | ) |
| Accrued taxes | | | (46,006 | ) | | | 19,960 | |
| Accrued interest | | | (4,376 | ) | | | (5,674 | ) |
| Other | | | 6,337 | | | | 2,373 | |
| | | | | | | |
| Net cash used for operating activities | | | (30,926 | ) | | | (5,681 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New financing- | | | | | | | | |
| Short-term borrowings, net | | | — | | | | 48,793 | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | — | | | | (100,000 | ) |
| Short-term borrowings, net | | | (14,369 | ) | | | — | |
| Common stock | | | (150,000 | ) | | | — | |
| Common stock dividend payments | | | (25,000 | ) | | | — | |
| | | | | | | |
| Net cash used for financing activities | | | (189,369 | ) | | | (51,207 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (21,126 | ) | | | (25,526 | ) |
| Sales of investment securities held in trusts | | | 335,860 | | | | 143,713 | |
| Purchases of investment securities held in trusts | | | (337,632 | ) | | | (146,056 | ) |
| Loans repayments from associated companies, net | | | 1,486 | | | | 85,383 | |
| Other | | | (1,396 | ) | | | (618 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (22,808 | ) | | | 56,896 | |
| | | | | | | |
| | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (243,103 | ) | | | 8 | |
| Cash and cash equivalents at beginning of period | | | 243,220 | | | | 120 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 117 | | | $ | 128 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
22
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | |
REVENUES: | | | | | | | | |
| Electric sales | | $ | 308,316 | | | $ | 385,936 | |
| Gross receipts tax collections | | | 16,529 | | | | 17,524 | |
| | | | | | | |
| Total revenues | | | 324,845 | | | | 403,460 | |
| | | | | | | |
| | | | | | | | | |
EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 47,484 | | | | 168,400 | |
| Purchased power from non-affiliates | | | 141,436 | | | | 91,423 | |
| Other operating expenses | | | 41,328 | | | | 72,394 | |
| Provision for depreciation | | | 14,573 | | | | 14,682 | |
| Amortization (deferral) of regulatory assets, net | | | 13,007 | | | | (9,966 | ) |
| General taxes | | | 20,736 | | | | 16,534 | |
| | | | | | | |
| Total expenses | | | 278,564 | | | | 353,467 | |
| | | | | | | |
| | | | | | | | | |
OPERATING INCOME | | | 46,281 | | | | 49,993 | |
| | | | | | | |
| | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income | | | 25 | | | | 1,613 | |
| Interest expense | | | (17,234 | ) | | | (17,290 | ) |
| Capitalized interest | | | 22 | | | | 140 | |
| | | | | | | |
| Total other expense | | | (17,187 | ) | | | (15,537 | ) |
| | | | | | | |
| | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 29,094 | | | | 34,456 | |
| | | | | | | | | |
INCOME TAXES | | | 11,788 | | | | 17,157 | |
| | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 17,306 | | | $ | 17,299 | |
| | | | | | | |
| | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
NET INCOME | | $ | 17,306 | | | $ | 17,299 | |
| | | | | | | |
| | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 1,585 | | | | 8,547 | |
| Unrealized gain on derivative hedges | | | 16 | | | | 16 | |
| | | | | | | |
| Other comprehensive income | | | 1,601 | | | | 8,563 | |
| Income tax expense related to other comprehensive income | | | 555 | | | | 3,284 | |
| | | | | | | |
| Other comprehensive income, net of tax | | | 1,046 | | | | 5,279 | |
| | | | | | | |
| | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 18,352 | | | $ | 22,578 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
23
PENNSYLVANIA ELECTRIC COMPANY
| THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 247 | | | $ | 86,230 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $5,168,000 and | | | | | | | | |
| $5,239,000, respectively, for uncollectible accounts) | | | 200,840 | | | | 209,335 | |
| Associated companies | | | 57,338 | | | | 98,954 | |
| Other | | | 5,058 | | | | 11,661 | |
| Notes receivable from associated companies | | | 25,376 | | | | 26,802 | |
| Prepayments and other | | | 18,996 | | | | 9,973 | |
| | | | 307,855 | | | | 442,955 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,326,786 | | | | 2,310,074 | |
| Less - Accumulated provision for depreciation | | | 896,146 | | | | 888,169 | |
| | | | 1,430,640 | | | | 1,421,905 | |
| Construction work in progress | | | 33,139 | | | | 36,907 | |
| | | | 1,463,779 | | | | 1,458,812 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 340,034 | | | | 388,641 | |
| Other | | | 10,210 | | | | 10,220 | |
| | | | 350,244 | | | | 398,861 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,688,521 | | | | 1,688,521 | |
| Regulatory assets | | | 497,723 | | | | 545,505 | |
| Pension assets (Note 5) | | | - | | | | 13,380 | |
| Property taxes | | | 77,319 | | | | 77,319 | |
| Other | | | 12,914 | | | | 12,777 | |
| | | | 2,276,477 | | | | 2,337,502 | |
| | | $ | 4,398,355 | | | $ | 4,638,130 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 127 | | | $ | 117 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 233,710 | | | | 339,728 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 55,534 | | | | 68,634 | |
| Other | | | 15,879 | | | | 17,166 | |
| Accrued taxes | | | 74,117 | | | | 90,511 | |
| Accrued interest | | | 39,261 | | | | 18,466 | |
| Other | | | 43,663 | | | | 45,440 | |
| | | | 462,291 | | | | 580,062 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity | | | | | | | | |
| Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | |
| 67,930,743 shares outstanding | | | 884,781 | | | | 884,897 | |
| Accumulated other comprehensive loss | | | (152,466 | ) | | | (138,158 | ) |
| Retained earnings | | | 510,824 | | | | 597,248 | |
| Total common stockholder's equity | | | 1,243,139 | | | | 1,343,987 | |
| Noncontrolling interest | | | 17,651 | | | | 20,592 | |
| Total equity | | | 1,260,790 | | | | 1,364,579 | |
| Long-term debt and other long-term obligations | | | 1,852,463 | | | | 1,872,750 | |
| | | | 3,113,253 | | | | 3,237,329 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 636,324 | | | | 644,745 | |
| Accumulated deferred investment tax credits | | | 11,626 | | | | 11,836 | |
| Retirement benefits | | | 82,281 | | | | 69,733 | |
| Other | | | 92,580 | | | | 94,425 | |
| | | | 822,811 | | | | 820,739 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 4,398,355 | | | $ | 4,638,130 | |
| | | | | | | | | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
(Unaudited)| | | | | | | | | |
| | | March 31, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 3 | | | $ | 5 | |
| Receivables- | | | | | | | | |
| Customers (net of allowance for uncollectible accounts of $3,395 in 2011 and $3,369 in 2010) | | | 139,058 | | | | 148,864 | |
| Associated companies | | | 16,921 | | | | 54,052 | |
| Other | | | 12,142 | | | | 11,314 | |
| Notes receivable from associated companies | | | 12,334 | | | | 14,404 | |
| Prepaid taxes | | | 47,126 | | | | 14,026 | |
| Other | | | 1,843 | | | | 1,592 | |
| | | | | | | |
| | | | 229,427 | | | | 244,257 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,545,211 | | | | 2,532,629 | |
| Less — Accumulated provision for depreciation | | | 939,247 | | | | 935,259 | |
| | | | | | | |
| | | | 1,605,964 | | | | 1,597,370 | |
| Construction work in progress | | | 40,799 | | | | 30,505 | |
| | | | | | | |
| | | | 1,646,763 | | | | 1,627,875 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 159,999 | | | | 152,928 | |
| Non-utility generation trusts | | | 80,275 | | | | 80,244 | |
| Other | | | 294 | | | | 297 | |
| | | | | | | |
| | | | 240,568 | | | | 233,469 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 768,628 | | | | 768,628 | |
| Regulatory assets | | | 179,092 | | | | 163,407 | |
| Power purchase contract asset | | | 4,169 | | | | 5,746 | |
| Other | | | 15,140 | | | | 19,287 | |
| | | | | | | |
| | | | 967,029 | | | | 957,068 | |
| | | | | | | |
| | | $ | 3,083,787 | | | $ | 3,062,669 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 45,000 | | | $ | 45,000 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 90,363 | | | | 101,338 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 41,231 | | | | 35,626 | |
| Other | | | 33,125 | | | | 41,420 | |
| Accrued taxes | | | 4,262 | | | | 5,075 | |
| Accrued interest | | | 24,069 | | | | 17,378 | |
| Other | | | 23,467 | | | | 22,541 | |
| | | | | | | |
| | | | 261,517 | | | | 268,378 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, $20 par value, authorized 5,400,000 shares- 4,427,577 shares outstanding | | | 88,552 | | | | 88,552 | |
| Other paid-in capital | | | 913,439 | | | | 913,519 | |
| Accumulated other comprehensive loss | | | (162,480 | ) | | | (163,526 | ) |
| Retained earnings | | | 58,299 | | | | 60,993 | |
| | | | | | | |
| Total common stockholder’s equity | | | 897,810 | | | | 899,538 | |
| Long-term debt and other long-term obligations | | | 1,072,339 | | | | 1,072,262 | |
| | | | | | | |
| | | | 1,970,149 | | | | 1,971,800 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 393,088 | | | | 371,877 | |
| Retirement benefits | | | 187,888 | | | | 187,621 | |
| Power purchase contract liability | | | 121,558 | | | | 116,972 | |
| Asset retirement obligations | | | 99,773 | | | | 98,132 | |
| Other | | | 49,814 | | | | 47,889 | |
| | | | | | | |
| | | | 852,121 | | | | 822,491 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 3,083,787 | | | $ | 3,062,669 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
24
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 17,306 | | | $ | 17,299 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 14,573 | | | | 14,682 | |
| Amortization (deferral) of regulatory assets, net | | | 13,007 | | | | (9,966 | ) |
| Deferred costs recoverable as regulatory assets | | | (17,771 | ) | | | (20,461 | ) |
| Deferred income taxes and investment tax credits, net | | | 16,648 | | | | 21,772 | |
| Accrued compensation and retirement benefits | | | 1,551 | | | | (169 | ) |
| Cash collateral paid, net | | | (2,124 | ) | | | (400 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 46,100 | | | | (4,641 | ) |
| Prepayments and other current assets | | | (33,350 | ) | | | (50,186 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (8,534 | ) | | | (1,348 | ) |
| Accrued taxes | | | (813 | ) | | | (2,142 | ) |
| Accrued interest | | | 6,691 | | | | 6,882 | |
| Other | | | 10,204 | | | | 7,162 | |
| | | | | | | |
| Net cash provided from (used for) operating activities | | | 63,488 | | | | (21,516 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New financing- | | | | | | | | |
| Short-term borrowings, net | | | — | | | | 51,334 | |
| Redemptions and repayments- | | | | | | | | |
| Short-term borrowings, net | | | (10,975 | ) | | | — | |
| Common stock dividend payments | | | (20,000 | ) | | | — | |
| Other | | | 26 | | | | (6 | ) |
| | | | | | | |
| Net cash provided from (used for) financing activities | | | (30,949 | ) | | | 51,328 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (31,128 | ) | | | (27,388 | ) |
| Loan repayments from associated companies, net | | | 2,070 | | | | 279 | |
| Sales of investment securities held in trusts | | | 178,927 | | | | 93,057 | |
| Purchases of investment securities held in trusts | | | (180,411 | ) | | | (94,464 | ) |
| Other | | | (1,999 | ) | | | (1,298 | ) |
| | | | | | | |
| Net cash used for investing activities | | | (32,541 | ) | | | (29,814 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (2 | ) | | | (2 | ) |
| Cash and cash equivalents at beginning of period | | | 5 | | | | 14 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 3 | | | $ | 12 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
25
\
| THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income (loss) | | $ | 13,995 | | | $ | (105,400 | ) |
| Adjustments to reconcile net income (loss) to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 18,111 | | | | 18,280 | |
| Amortization of regulatory assets, net | | | 45,139 | | | | 256,737 | |
| Deferral of new regulatory assets | | | - | | | | (94,816 | ) |
| Deferred income taxes and investment tax credits, net | | | (13,627 | ) | | | (61,525 | ) |
| Accrued compensation and retirement benefits | | | 2,282 | | | | 1,828 | |
| Accrued regulatory obligations | | | (26 | ) | | | 12,057 | |
| Electric service prepayment programs | | | - | | | | (2,695 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 70,633 | | | | (44,808 | ) |
| Prepayments and other current assets | | | (9,133 | ) | | | 785 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (14,387 | ) | | | 18,470 | |
| Accrued taxes | | | (16,616 | ) | | | (16,274 | ) |
| Accrued interest | | | 20,795 | | | | 27,614 | |
| Other | | | (2,636 | ) | | | 346 | |
| Net cash provided from operating activities | | | 114,530 | | | | 10,599 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (26 | ) | | | (181 | ) |
| Short-term borrowings, net | | | (126,334 | ) | | | (4,086 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (100,000 | ) | | | (10,000 | ) |
| Other | | | (3,365 | ) | | | (2,840 | ) |
| Net cash used for financing activities | | | (229,725 | ) | | | (17,107 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (19,735 | ) | | | (24,900 | ) |
| Loans to associated companies, net | | | 1,426 | | | | (3,683 | ) |
| Redemptions of lessor notes | | | 48,606 | | | | 37,068 | |
| Other | | | (1,085 | ) | | | (1,970 | ) |
| Net cash provided from investing activities | | | 29,212 | | | | 6,515 | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (85,983 | ) | | | 7 | |
| Cash and cash equivalents at beginning of period | | | 86,230 | | | | 226 | |
| Cash and cash equivalents at end of period | | $ | 247 | | | $ | 233 | |
| | | | | | | | | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| THE TOLEDO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| STATEMENTS OF INCOME | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 125,431 | | | $ | 237,085 | |
| Excise tax collections | | | 7,041 | | | | 7,729 | |
| Total revenues | | | 132,472 | | | | 244,814 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 47,000 | | | | 125,324 | |
| Purchased power from non-affiliates | | | 26,109 | | | | 40,537 | |
| Other operating costs | | | 25,545 | | | | 45,004 | |
| Provision for depreciation | | | 7,950 | | | | 7,572 | |
| Amortization (deferral) of regulatory assets, net | | | (8,499 | ) | | | 9,897 | |
| General taxes | | | 13,461 | | | | 14,250 | |
| Total expenses | | | 111,566 | | | | 242,584 | |
| | | | | | | | | |
| OPERATING INCOME | | | 20,906 | | | | 2,230 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | | 3,800 | | | | 5,484 | |
| Miscellaneous expense | | | (1,406 | ) | | | (1,340 | ) |
| Interest expense | | | (10,487 | ) | | | (5,533 | ) |
| Capitalized interest | | | 78 | | | | 42 | |
| Total other expense | | | (8,015 | ) | | | (1,347 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 12,891 | | | | 883 | |
| | | | | | | | | |
| INCOME TAX EXPENSE (BENEFIT) | | | 5,382 | | | | (109 | ) |
| | | | | | | | | |
| NET INCOME | | | 7,509 | | | | 992 | |
| | | | | | | | | |
| Less: Noncontrolling interest income | | | 3 | | | | 2 | |
| | | | | | | | | |
| EARNINGS AVAILABLE TO PARENT | | $ | 7,506 | | | $ | 990 | |
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 7,509 | | | $ | 992 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pension and other postretirement benefits | | | 296 | | | | 133 | |
| Change in unrealized gain on available-for-sale securities | | | 369 | | | | (809 | ) |
| Other comprehensive income (loss) | | | 665 | | | | (676 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 170 | | | | (19 | ) |
| Other comprehensive income (loss), net of tax | | | 495 | | | | (657 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | | 8,004 | | | | 335 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 3 | | | | 2 | |
| | | | | | | | | |
| COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 8,001 | | | $ | 333 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| THE TOLEDO EDISON COMPANY | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 87,296 | | | $ | 436,712 | |
| Receivables- | | | | | | | | |
| Customers | | | 218 | | | | 75 | |
| Associated companies | | | 58,811 | | | | 90,191 | |
| Other (less accumulated provisions of $207,000 and $208,000, | | | | | |
| respectively, for uncollectible accounts) | | | 19,499 | | | | 20,180 | |
| Notes receivable from associated companies | | | 118,689 | | | | 85,101 | |
| Prepayments and other | | | 11,680 | | | | 7,111 | |
| | | | 296,193 | | | | 639,370 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 921,768 | | | | 912,930 | |
| Less - Accumulated provision for depreciation | | | 431,737 | | | | 427,376 | |
| | | | 490,031 | | | | 485,554 | |
| Construction work in progress | | | 8,913 | | | | 9,069 | |
| | | | 498,944 | | | | 494,623 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes (Note 7) | | | 103,848 | | | | 124,357 | |
| Nuclear plant decommissioning trusts | | | 73,583 | | | | 73,935 | |
| Other | | | 1,558 | | | | 1,580 | |
| | | | 178,989 | | | | 199,872 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 500,576 | | | | 500,576 | |
| Regulatory assets | | | 81,616 | | | | 69,557 | |
| Property taxes | | | 23,658 | | | | 23,658 | |
| Other | | | 67,753 | | | | 55,622 | |
| | | | 673,603 | | | | 649,413 | |
| | | $ | 1,647,729 | | | $ | 1,983,278 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 222 | | | $ | 222 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 43,730 | | | | 78,341 | |
| Other | | | 7,509 | | | | 8,312 | |
| Notes payable to associated companies | | | - | | | | 225,975 | |
| Accrued taxes | | | 20,827 | | | | 25,734 | |
| Lease market valuation liability | | | 36,900 | | | | 36,900 | |
| Other | | | 64,724 | | | | 29,273 | |
| | | | 173,912 | | | | 404,757 | |
| CAPITALIZATION | | | | | | | | |
| Common stockholder's equity | | | | | | | | |
| Common stock, $5 par value, authorized 60,000,000 shares - | | | | | |
| 29,402,054 shares outstanding | | | 147,010 | | | | 147,010 | |
| Other paid-in capital | | | 178,089 | | | | 178,181 | |
| Accumulated other comprehensive loss | | | (49,308 | ) | | | (49,803 | ) |
| Retained earnings | | | 91,995 | | | | 214,490 | |
| Total common stockholder's equity | | | 367,786 | | | | 489,878 | |
| Noncontrolling interest | | | 2,698 | | | | 2,696 | |
| Total equity | | | 370,484 | | | | 492,574 | |
| Long-term debt and other long-term obligations | | | 600,450 | | | | 600,443 | |
| | | | 970,934 | | | | 1,093,017 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 105,271 | | | | 80,508 | |
| Accumulated deferred investment tax credits | | | 6,258 | | | | 6,367 | |
| Lease market valuation liability (Note 7) | | | 226,975 | | | | 236,200 | |
| Retirement benefits | | | 67,304 | | | | 65,988 | |
| Asset retirement obligations | | | 32,831 | | | | 32,290 | |
| Other | | | 64,244 | | | | 64,151 | |
| | | | 502,883 | | | | 485,504 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 1,647,729 | | | $ | 1,983,278 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| THE TOLEDO EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | | | | | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 7,509 | | | $ | 992 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 7,950 | | | | 7,572 | |
| Amortization (deferral) of regulatory assets, net | | | (8,499 | ) | | | 9,897 | |
| Purchased power cost recovery reconciliation | | | 41 | | | | 2,912 | |
| Deferred rents and lease market valuation liability | | | 6,141 | | | | 6,141 | |
| Deferred income taxes and investment tax credits, net | | | 11,287 | | | | (2,151 | ) |
| Accrued compensation and retirement benefits | | | 837 | | | | 397 | |
| Accrued regulatory obligations | | | (246 | ) | | | 4,450 | |
| Electric service prepayment programs | | | - | | | | (1,240 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 45,376 | | | | (8,395 | ) |
| Prepayments and other current assets | | | (4,569 | ) | | | 492 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (35,414 | ) | | | 9,018 | |
| Accrued taxes | | | (4,933 | ) | | | (4,904 | ) |
| Accrued interest | | | 10,050 | | | | 4,613 | |
| Other | | | (4,373 | ) | | | 1,465 | |
| Net cash provided from (used for) operating activities | | | 31,157 | | | | 31,259 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | - | | | | (181 | ) |
| Short-term borrowings, net | | | (225,975 | ) | | | (3,977 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (130,000 | ) | | | (10,000 | ) |
| Other | | | (58 | ) | | | (39 | ) |
| Net cash provided from (used for) financing activities | | | (356,033 | ) | | | (14,197 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (9,597 | ) | | | (12,233 | ) |
| Loans to associated companies, net | | | (33,587 | ) | | | (21,528 | ) |
| Redemption of lessor notes | | | 20,509 | | | | 18,358 | |
| Sales of investment securities held in trusts | | | 31,067 | | | | 44,270 | |
| Purchases of investment securities held in trusts | | | (31,705 | ) | | | (44,856 | ) |
| Other | | | (1,227 | ) | | | (1,072 | ) |
| Net cash provided from (used for) investing activities | | | (24,540 | ) | | | (17,061 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (349,416 | ) | | | 1 | |
| Cash and cash equivalents at beginning of period | | | 436,712 | | | | 14 | |
| Cash and cash equivalents at end of period | | $ | 87,296 | | | $ | 15 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 691,392 | | | $ | 760,920 | |
| Excise tax collections | | | 12,352 | | | | 12,731 | |
| Total revenues | | | 703,744 | | | | 773,651 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power | | | 414,016 | | | | 481,241 | |
| Other operating costs | | | 95,660 | | | | 85,870 | |
| Provision for depreciation | | | 27,971 | | | | 25,103 | |
| Amortization of regulatory assets, net | | | 69,448 | | | | 86,831 | |
| General taxes | | | 16,436 | | | | 17,496 | |
| Total expenses | | | 623,531 | | | | 696,541 | |
| | | | | | | | | |
| OPERATING INCOME | | | 80,213 | | | | 77,110 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income | | | 1,833 | | | | 805 | |
| Interest expense | | | (29,423 | ) | | | (27,868 | ) |
| Capitalized interest | | | 133 | | | | 62 | |
| Total other expense | | | (27,457 | ) | | | (27,001 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 52,756 | | | | 50,109 | |
| | | | | | | | | |
| INCOME TAXES | | | 23,530 | | | | 22,551 | |
| | | | | | | | | |
| NET INCOME | | | 29,226 | | | | 27,558 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 15,928 | | | | 4,121 | |
| Unrealized gain on derivative hedges | | | 69 | | | | 69 | |
| Other comprehensive income | | | 15,997 | | | | 4,190 | |
| Income tax expense related to other comprehensive income | | | 6,558 | | | | 1,430 | |
| Other comprehensive income, net of tax | | | 9,439 | | | | 2,760 | |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 38,665 | | | $ | 30,318 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 1 | | | $ | 27 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,668,000 and $3,506,000 | | | | | |
| respectively, for uncollectible accounts) | | | 282,611 | | | | 300,991 | |
| Associated companies | | | 42 | | | | 12,884 | |
| Other | | | 19,842 | | | | 21,877 | |
| Notes receivable - associated companies | | | 110,552 | | | | 102,932 | |
| Prepaid taxes | | | 17,044 | | | | 34,930 | |
| Other | | | 14,370 | | | | 12,945 | |
| | | | 444,462 | | | | 486,586 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 4,493,540 | | | | 4,463,490 | |
| Less - Accumulated provision for depreciation | | | 1,630,664 | | | | 1,617,639 | |
| | | | 2,862,876 | | | | 2,845,851 | |
| Construction work in progress | | | 49,025 | | | | 54,251 | |
| | | | 2,911,901 | | | | 2,900,102 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear fuel disposal trust | | | 202,532 | | | | 199,677 | |
| Nuclear plant decommissioning trusts | | | 172,984 | | | | 166,768 | |
| Other | | | 2,158 | | | | 2,149 | |
| | | | 377,674 | | | | 368,594 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,810,936 | | | | 1,810,936 | |
| Regulatory assets | | | 855,740 | | | | 888,143 | |
| Other | | | 22,902 | | | | 27,096 | |
| | | | 2,689,578 | | | | 2,726,175 | |
| | | $ | 6,423,615 | | | $ | 6,481,457 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 31,084 | | | $ | 30,639 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 24,346 | | | | 26,882 | |
| Other | | | 139,945 | | | | 168,093 | |
| Accrued taxes | | | 42,274 | | | | 12,594 | |
| Accrued interest | | | 30,072 | | | | 18,256 | |
| Other | | | 98,468 | | | | 111,156 | |
| | | | 366,189 | | | | 367,620 | |
| CAPITALIZATION | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | |
| 13,628,447 shares outstanding | | | 136,284 | | | | 136,284 | |
| Other paid-in capital | | | 2,506,864 | | | | 2,507,049 | |
| Accumulated other comprehensive loss | | | (233,573 | ) | | | (243,012 | ) |
| Retained earnings | | | 139,300 | | | | 200,075 | |
| Total common stockholder's equity | | | 2,548,875 | | | | 2,600,396 | |
| Long-term debt and other long-term obligations | | | 1,794,558 | | | | 1,801,589 | |
| | | | 4,343,433 | | | | 4,401,985 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Power purchase contract liability | | | 399,762 | | | | 399,105 | |
| Accumulated deferred income taxes | | | 701,998 | | | | 687,545 | |
| Nuclear fuel disposal costs | | | 196,551 | | | | 196,511 | |
| Asset retirement obligations | | | 103,209 | | | | 101,568 | |
| Retirement benefits | | | 131,718 | | | | 150,603 | |
| Other | | | 180,755 | | | | 176,520 | |
| | | | 1,713,993 | | | | 1,711,852 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 6,423,615 | | | $ | 6,481,457 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| JERSEY CENTRAL POWER & LIGHT COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 29,226 | | | $ | 27,558 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 27,971 | | | | 25,103 | |
| Amortization of regulatory assets, net | | | 69,448 | | | | 86,831 | |
| Deferred purchased power and other costs | | | (32,775 | ) | | | (28,369 | ) |
| Deferred income taxes and investment tax credits, net | | | (2,082 | ) | | | (6,408 | ) |
| Accrued compensation and retirement benefits | | | (5,847 | ) | | | (7,481 | ) |
| Cash collateral returned to suppliers | | | (23,400 | ) | | | (209 | ) |
| Decrease in operating assets: | | | | | | | | |
| Receivables | | | 33,257 | | | | 27,143 | |
| Prepayments and other current assets | | | 16,472 | | | | 4,792 | |
| Increase (decrease) in operating liabilities: | | | | | | | | |
| Accounts payable | | | (40,992 | ) | | | (30,029 | ) |
| Accrued taxes | | | 50,857 | | | | 33,114 | |
| Accrued interest | | | 11,816 | | | | 21,249 | |
| Tax collections payable | | | 14,544 | | | | 5,935 | |
| Other | | | 466 | | | | 1,955 | |
| Net cash provided from operating activities | | | 148,961 | | | | 161,184 | |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | - | | | | 299,619 | |
| Redemptions and Repayments- | | | | | | | | |
| Common stock | | | - | | | | (150,000 | ) |
| Long-term debt | | | (6,773 | ) | | | (6,402 | ) |
| Short-term borrowings, net | | | - | | | | (121,380 | ) |
| Dividend Payments- | | | | | | | | |
| Common stock | | | (90,000 | ) | | | (63,000 | ) |
| Other | | | - | | | | (2,152 | ) |
| Net cash used for financing activities | | | (96,773 | ) | | | (43,315 | ) |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (37,338 | ) | | | (37,372 | ) |
| Loans to associated companies, net | | | (7,620 | ) | | | (75,108 | ) |
| Sales of investment securities held in trusts | | | 190,198 | | | | 115,483 | |
| Purchases of investment securities held in trusts | | | (194,748 | ) | | | (120,062 | ) |
| Other | | | (2,706 | ) | | | (872 | ) |
| Net cash used for investing activities | | | (52,214 | ) | | | (117,931 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (26 | ) | | | (62 | ) |
| Cash and cash equivalents at beginning of period | | | 27 | | | | 66 | |
| Cash and cash equivalents at end of period | | $ | 1 | | | $ | 4 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| METROPOLITAN EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 451,560 | | | $ | 409,686 | |
| Gross receipts tax collections | | | 21,567 | | | | 19,983 | |
| Total revenues | | | 473,127 | | | | 429,669 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 161,080 | | | | 100,077 | |
| Purchased power from non-affiliates | | | 91,928 | | | | 123,911 | |
| Other operating costs | | | 101,983 | | | | 106,357 | |
| Provision for depreciation | | | 12,758 | | | | 12,139 | |
| Amortization of regulatory assets, net | | | 48,800 | | | | 27,591 | |
| General taxes | | | 21,740 | | | | 21,935 | |
| Total expenses | | | 438,289 | | | | 392,010 | |
| | | | | | | | | |
| OPERATING INCOME | | | 34,838 | | | | 37,659 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Interest income | | | 1,217 | | | | 3,186 | |
| Miscellaneous income | | | 2,173 | | | | 856 | |
| Interest expense | | | (13,773 | ) | | | (13,359 | ) |
| Capitalized interest | | | 126 | | | | 15 | |
| Total other expense | | | (10,257 | ) | | | (9,302 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 24,581 | | | | 28,357 | |
| | | | | | | | | |
| INCOME TAXES | | | 12,266 | | | | 11,735 | |
| | | | | | | | | |
| NET INCOME | | | 12,315 | | | | 16,622 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 9,709 | | | | 4,553 | |
| Unrealized gain on derivative hedges | | | 84 | | | | 84 | |
| Other comprehensive income | | | 9,793 | | | | 4,637 | |
| Income tax expense related to other comprehensive income | | | 4,177 | | | | 1,793 | |
| Other comprehensive income, net of tax | | | 5,616 | | | | 2,844 | |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 17,931 | | | $ | 19,466 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these | |
| financial statements. | | | | | | | | |
| METROPOLITAN EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 128 | | | $ | 120 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $4,341,000 and $4,044,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 171,347 | | | | 171,052 | |
| Associated companies | | | 40,651 | | | | 29,413 | |
| Other | | | 11,189 | | | | 11,650 | |
| Notes receivable from associated companies | | | 11,767 | | | | 97,150 | |
| Prepaid taxes | | | 67,672 | | | | 15,229 | |
| Other | | | 1,057 | | | | 1,459 | |
| | | | 303,811 | | | | 326,073 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,178,625 | | | | 2,162,815 | |
| Less - Accumulated provision for depreciation | | | 818,724 | | | | 810,746 | |
| | | | 1,359,901 | | | | 1,352,069 | |
| Construction work in progress | | | 20,450 | | | | 14,901 | |
| | | | 1,380,351 | | | | 1,366,970 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 275,356 | | | | 266,479 | |
| Other | | | 888 | | | | 890 | |
| | | | 276,244 | | | | 267,369 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 416,499 | | | | 416,499 | |
| Regulatory assets | | | 392,651 | | | | 356,754 | |
| Power purchase contract asset | | | 136,702 | | | | 176,111 | |
| Other | | | 41,513 | | | | 36,544 | |
| | | | 987,365 | | | | 985,908 | |
| | | $ | 2,947,771 | | | $ | 2,946,320 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 28,500 | | | $ | 128,500 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 48,793 | | | | - | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 51,742 | | | | 40,521 | |
| Other | | | 22,550 | | | | 41,050 | |
| Accrued taxes | | | 31,130 | | | | 11,170 | |
| Accrued interest | | | 11,688 | | | | 17,362 | |
| Other | | | 25,971 | | | | 24,520 | |
| | | | 220,374 | | | | 263,123 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, without par value, authorized 900,000 shares- | | | | | | | | |
| 859,500 shares outstanding | | | 1,196,943 | | | | 1,197,070 | |
| Accumulated other comprehensive loss | | | (137,935 | ) | | | (143,551 | ) |
| Retained Earnings | | | 16,714 | | | | 4,399 | |
| Total common stockholder's equity | | | 1,075,722 | | | | 1,057,918 | |
| Long-term debt and other long-term obligations | | | 713,900 | | | | 713,873 | |
| | | | 1,789,622 | | | | 1,771,791 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 457,231 | | | | 453,462 | |
| Accumulated deferred investment tax credits | | | 7,201 | | | | 7,313 | |
| Nuclear fuel disposal costs | | | 44,400 | | | | 44,391 | |
| Asset retirement obligations | | | 183,309 | | | | 180,297 | |
| Retirement benefits | | | 30,288 | | | | 33,605 | |
| Power purchase contract liability | | | 167,120 | | | | 143,135 | |
| Other | | | 48,226 | | | | 49,203 | |
| | | | 937,775 | | | | 911,406 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 2,947,771 | | | $ | 2,946,320 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| METROPOLITAN EDISON COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 12,315 | | | $ | 16,622 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 12,758 | | | | 12,139 | |
| Amortization of regulatory assets, net | | | 48,800 | | | | 27,591 | |
| Deferred costs recoverable as regulatory assets | | | (18,276 | ) | | | (19,633 | ) |
| Deferred income taxes and investment tax credits, net | | | (10,308 | ) | | | 4,657 | |
| Accrued compensation and retirement benefits | | | (2,527 | ) | | | 1,029 | |
| Cash collateral to suppliers | | | (700 | ) | | | (9,500 | ) |
| Increase in operating assets- | | | | | | | | |
| Receivables | | | (5,083 | ) | | | (9,860 | ) |
| Prepayments and other current assets | | | (52,040 | ) | | | (50,422 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (7,279 | ) | | | (8,058 | ) |
| Accrued taxes | | | 19,960 | | | | (7,749 | ) |
| Accrued interest | | | (5,674 | ) | | | 4,803 | |
| Other | | | 2,373 | | | | 2,460 | |
| Net cash used for operating activities | | | (5,681 | ) | | | (35,921 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | - | | | | 300,000 | |
| Short-term borrowings, net | | | 48,793 | | | | - | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (100,000 | ) | | | - | |
| Short-term borrowings, net | | | - | | | | (15,003 | ) |
| Other | | | - | | | | (2,150 | ) |
| Net cash provided from (used for) financing activities | | | (51,207 | ) | | | 282,847 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (25,526 | ) | | | (25,922 | ) |
| Sales of investment securities held in trusts | | | 143,713 | | | | 27,800 | |
| Purchases of investment securities held in trusts | | | (146,056 | ) | | | (29,821 | ) |
| Loan repayments from (loans to) associated companies, net | | | 85,383 | | | | (218,168 | ) |
| Other | | | (618 | ) | | | (832 | ) |
| Net cash provided from (used for) investing activities | | | 56,896 | | | | (246,943 | ) |
| | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 8 | | | | (17 | ) |
| Cash and cash equivalents at beginning of period | | | 120 | | | | 144 | |
| Cash and cash equivalents at end of period | | $ | 128 | | | $ | 127 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these | |
| financial statements. | | | | | | | | |
| PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| REVENUES: | | | | | | |
| Electric sales | | $ | 385,936 | | | $ | 371,293 | |
| Gross receipts tax collections | | | 17,524 | | | | 17,292 | |
| Total revenues | | | 403,460 | | | | 388,585 | |
| | | | | | | | | |
| EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | | 168,400 | | | | 96,081 | |
| Purchased power from non-affiliates | | | 91,423 | | | | 127,166 | |
| Other operating costs | | | 72,394 | | | | 77,289 | |
| Provision for depreciation | | | 14,682 | | | | 14,455 | |
| Amortization (deferral) of regulatory assets, net | | | (9,966 | ) | | | 8,776 | |
| General taxes | | | 16,534 | | | | 20,593 | |
| Total expenses | | | 353,467 | | | | 344,360 | |
| | | | | | | | | |
| OPERATING INCOME | | | 49,993 | | | | 44,225 | |
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income | | | 1,613 | | | | 798 | |
| Interest expense | | | (17,290 | ) | | | (13,233 | ) |
| Capitalized interest | | | 140 | | | | 22 | |
| Total other expense | | | (15,537 | ) | | | (12,413 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 34,456 | | | | 31,812 | |
| | | | | | | | | |
| INCOME TAXES | | | 17,157 | | | | 13,122 | |
| | | | | | | | | |
| NET INCOME | | | 17,299 | | | | 18,690 | |
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | | | | | | | | |
| Pension and other postretirement benefits | | | 8,547 | | | | 2,955 | |
| Unrealized gain on derivative hedges | | | 16 | | | | 16 | |
| Change in unrealized gain on available-for-sale securities | | | - | | | | (22 | ) |
| Other comprehensive income | | | 8,563 | | | | 2,949 | |
| Income tax expense related to other comprehensive income | | | 3,284 | | | | 1,055 | |
| Other comprehensive income, net of tax | | | 5,279 | | | | 1,894 | |
| | | | | | | | | |
| TOTAL COMPREHENSIVE INCOME | | $ | 22,578 | | | $ | 20,584 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
| CONSOLIDATED BALANCE SHEETS | |
| (Unaudited) | |
| | | March 31, | | | December 31, | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| ASSETS | | | | | | |
| CURRENT ASSETS: | | | | | | |
| Cash and cash equivalents | | $ | 12 | | | $ | 14 | |
| Receivables- | | | | | | | | |
| Customers (less accumulated provisions of $3,768,000 and $3,483,000, | | | | | | | | |
| respectively, for uncollectible accounts) | | | 138,010 | | | | 139,302 | |
| Associated companies | | | 92,197 | | | | 77,338 | |
| Other | | | 14,696 | | | | 18,320 | |
| Notes receivable from associated companies | | | 14,311 | | | | 14,589 | |
| Prepaid taxes | | | 69,403 | | | | 18,946 | |
| Other | | | 1,128 | | | | 1,400 | |
| | | | 329,757 | | | | 269,909 | |
| UTILITY PLANT: | | | | | | | | |
| In service | | | 2,453,558 | | | | 2,431,737 | |
| Less - Accumulated provision for depreciation | | | 908,550 | | | | 901,990 | |
| | | | 1,545,008 | | | | 1,529,747 | |
| Construction work in progress | | | 22,966 | | | | 24,205 | |
| | | | 1,567,974 | | | | 1,553,952 | |
| OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 147,757 | | | | 142,603 | |
| Non-utility generation trusts | | | 120,764 | | | | 120,070 | |
| Other | | | 287 | | | | 289 | |
| | | | 268,808 | | | | 262,962 | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 768,628 | | | | 768,628 | |
| Regulatory assets | | | 119,483 | | | | 9,045 | |
| Power purchase contract asset | | | 5,456 | | | | 15,362 | |
| Other | | | 17,447 | | | | 19,143 | |
| | | | 911,014 | | | | 812,178 | |
| | | $ | 3,077,553 | | | $ | 2,899,001 | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 69,310 | | | $ | 69,310 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 92,807 | | | | 41,473 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 56,911 | | | | 39,884 | |
| Other | | | 23,680 | | | | 41,990 | |
| Accrued taxes | | | 4,267 | | | | 6,409 | |
| Accrued interest | | | 24,480 | | | | 17,598 | |
| Other | | | 23,300 | | | | 22,741 | |
| | | | 294,755 | | | | 239,405 | |
| CAPITALIZATION: | | | | | | | | |
| Common stockholder's equity- | | | | | | | | |
| Common stock, $20 par value, authorized 5,400,000 shares- | | | | | | | | |
| 4,427,577 shares outstanding | | | 88,552 | | | | 88,552 | |
| Other paid-in capital | | | 913,403 | | | | 913,437 | |
| Accumulated other comprehensive loss | | | (156,825 | ) | | | (162,104 | ) |
| Retained earnings | | | 108,800 | | | | 91,501 | |
| Total common stockholder's equity | | | 953,930 | | | | 931,386 | |
| Long-term debt and other long-term obligations | | | 1,072,190 | | | | 1,072,181 | |
| | | | 2,026,120 | | | | 2,003,567 | |
| NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 274,846 | | | | 242,040 | |
| Retirement benefits | | | 166,509 | | | | 174,306 | |
| Asset retirement obligations | | | 93,374 | | | | 91,841 | |
| Power purchase contract liability | | | 171,244 | | | | 100,849 | |
| Other | | | 50,705 | | | | 46,993 | |
| | | | 756,678 | | | | 656,029 | |
| COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | |
| | | $ | 3,077,553 | | | $ | 2,899,001 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
| PENNSYLVANIA ELECTRIC COMPANY | |
| | | | | | | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| | | 2010 | | | 2009 | |
| | | (In thousands) | |
| | | | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 17,299 | | | $ | 18,690 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | |
| Provision for depreciation | | | 14,682 | | | | 14,455 | |
| Amortization (deferral) of regulatory assets, net | | | (9,966 | ) | | | 8,776 | |
| Deferred costs recoverable as regulatory assets | | | (20,461 | ) | | | (20,022 | ) |
| Deferred income taxes and investment tax credits, net | | | 21,772 | | | | 11,833 | |
| Accrued compensation and retirement benefits | | | (169 | ) | | | 431 | |
| Cash collateral | | | (400 | ) | | | - | |
| Increase in operating assets- | | | | | | | | |
| Receivables | | | (4,641 | ) | | | (1,709 | ) |
| Prepayments and other current assets | | | (50,186 | ) | | | (49,707 | ) |
| Increase (Decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (1,348 | ) | | | (5,340 | ) |
| Accrued taxes | | | (2,142 | ) | | | (9,065 | ) |
| Accrued interest | | | 6,882 | | | | 599 | |
| Other | | | 7,162 | | | | (988 | ) |
| Net cash used for operating activities | | | (21,516 | ) | | | (32,047 | ) |
| | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | 51,334 | | | | 80,632 | |
| Dividend Payments- | | | | | | | | |
| Common stock | | | - | | | | (15,000 | ) |
| Other | | | (6 | ) | | | - | |
| Net cash provided from financing activities | | | 51,328 | | | | 65,632 | |
| | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (27,388 | ) | | | (28,190 | ) |
| Sales of investment securities held in trusts | | | 93,057 | | | | 18,800 | |
| Purchases of investment securities held in trusts | | | (94,464 | ) | | | (22,108 | ) |
| Loan repayments to associated companies, net | | | 279 | | | | (365 | ) |
| Other | | | (1,298 | ) | | | (1,732 | ) |
| Net cash used for investing activities | | | (29,814 | ) | | | (33,595 | ) |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (2 | ) | | | (10 | ) |
| Cash and cash equivalents at beginning of period | | | 14 | | | | 23 | |
| Cash and cash equivalents at end of period | | $ | 12 | | | $ | 13 | |
| | | | | | | | | |
| The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. | |
COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
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, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL Company), FES and its subsidiaries FGCO and NGC, and FESC.
AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE remaining as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy (See Note 2, Merger).
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC, the NERC and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the 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.
These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 20092010 for FirstEnergy, FES and the Utilities,Utility Registrants, as applicable.applicable, and the Current Report on Form 8-K filed by FirstEnergy on February 25, 2011, as amended on April 19, 2011. The consolidated unaudited financial statements of FirstEnergy, FES and each of the UtilitiesUtility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. 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.
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. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 6)7, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. 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'sentity’s earnings is reported in the Consolidated Statements of Income.
2. MERGER
2.Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub), and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
The merger created a combined company with increased scale and scope and greater diversification in energy delivery, generation and transmission. The combined company is the largest U.S. diversified electric utility by customers and operates one of the largest unregulated power generation fleets in the United States with FirstEnergy’s total current capacity of approximately 23,000 MW, which includes approximately 3,000 MW of regulated generation.
26
The total consideration in the merger was based on the closing price of a share of FirstEnergy common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):
| | | | | |
|
| Shares of Allegheny common stock outstanding on February 24, 2011 | | | 170 | |
| Exchange ratio | | | 0.667 | |
| | | | |
| Number of shares of FirstEnergy common stock issued | | | 113 | |
| Closing price of FirstEnergy common stock on February 24, 2011 | | $ | 38.16 | |
| | | | |
| Fair value of shares issued by FirstEnergy | | $ | 4,327 | |
| Fair value of replacement share-based compensation awards relating to pre-merger service | | | 27 | |
| | | | |
| Total consideration transferred | | $ | 4,354 | |
| | | | |
The preliminary allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and deferred income taxes. The preliminary allocation of the purchase price is as follows:
| | | | | |
| | | Preliminary | |
| | | Purchase Price | |
| (In millions) | | Allocation | |
| | | | | |
| Current assets | | $ | 1,509 | |
| Property, plant and equipment | | | 9,656 | |
| Investments | | | 138 | |
| Goodwill | | | 952 | |
| Other noncurrent assets | | | 1,262 | |
| Current liabilities | | | (714 | ) |
| Noncurrent liabilities | | | (3,453 | ) |
| Long-term debt and other long-term obligations | | | (4,996 | ) |
| | | | |
| | | $ | 4,354 | |
| | | | |
Assumptions and estimates underlying the fair value adjustments are subject to change pending further review of the assets acquired and liabilities assumed.
The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $952 million was assigned entirely to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.
Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | | | | | |
| | | Regulated | | | Energy | | | Independent | | | Other/ | | | | |
| (In millions) | | Distribution | | | Services | | | Transmission | | | Corporate | | | Consolidated | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2010 | | $ | 5,551 | | | $ | 24 | | | $ | — | | | $ | — | | | $ | 5,575 | |
| | | | | | | | | | | | | | | | | | | | | |
| Merger with Allegheny | | | — | | | | 952 | | | | — | | | | — | | | | 952 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at March 31, 2011 | | $ | 5,551 | | | $ | 976 | | | $ | — | | | $ | — | | | $ | 6,527 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | |
27
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:
| | | | | | | | | |
| | | Preliminary | | | Weighted Average | |
| (In millions) | | Valuation | | | Amortization Period | |
| Above market contracts: | | | | | | | | |
| Energy supply contracts | | $ | 189 | | | 10 years |
| NUG contracts | | | 124 | | | 25 years |
| Coal supply contracts | | | 525 | | | 8 years |
| | | | | | | | |
| | | | 838 | | | | | |
| | | | | | | | | |
| Below market contracts: | | | | | | | | |
| NUG contracts | | | 143 | | | 13 years |
| Coal supply contracts | | | 86 | | | 7 years |
| Transportation contract | | | 35 | | | 8 years |
| | | | | | | | |
| | | | 264 | | | | | |
| | | | | | | | |
| | | | | | | | | |
| | | $ | 574 | | | | | |
| | | | | | | | |
The fair value measurements of intangible assets and liabilities were primarily based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.
The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.
The fair value of coal supply contracts was determined in a similar manner based on the present value of the above/below market cash flows attributable to the contracts. The fair value of these contracts will be amortized based on expected deliveries under each contract.
Total intangible assets recorded on FirstEnergy’s Consolidated Balance Sheet as of March 31, 2011 are as follows:
| | | | | |
| | | Intangible | |
| (In millions) | | Assets | |
| Purchase contract assets | | | | |
| NUG | | $ | 241 | |
| OVEC | | | 52 | |
| | | | |
| | | | 293 | |
| | | | | |
| Intangible assets | | | | |
| Coal contracts | | | 520 | |
| FES customer intangible assets | | | 132 | |
| Energy contracts | | | 130 | |
| | | | |
| | | | 782 | |
| | | | |
| | | | | |
| | | $ | 1,075 | |
| | | | |
Other intangible assets acquired in the Allegheny merger include land easements and software, having a fair value of $126 million, are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of March 31, 2011.
In connection with the merger, FirstEnergy recorded approximately $82 million ($68 million net of tax) and $14 million ($10 million net of tax) of merger transaction costs during the first quarter of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statement of Income. Merger transaction costs recognized in the first quarter of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.
28
FirstEnergy also recorded approximately $75 million in merger integration costs during the first quarter of 2011, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review FirstEnergy management determined the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax).
The amounts of revenue and earnings of Allegheny since the merger date included in FirstEnergy’s Consolidated Statement of Income for the quarter ended March 31, 2011 are as follows:
| | | | | |
| | | February 26 - | |
| (In millions, except per share amounts) | | March 31, 2011 | |
| | | | | |
| Total revenues | | $ | 437 | |
Net Income(1) | | | (46 | ) |
| | | | | |
| Basic Earnings Per Share | | $ | (0.13 | ) |
| Diluted Earnings Per Share | | $ | (0.13 | ) |
| | |
| (1) | | Includes Allegheny’s after-tax merger costs of $52 million. |
Pro Forma Financial Information
The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with Allegheny had taken place on January 1, 2010. The unaudited pro forma information has been calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.
FirstEnergy and Allegheny both incurred non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Approximately $83 million and $27 million of combined pre-tax transaction costs were incurred in the three months ended March 31, 2011 and March 31, 2010, respectively. In addition, in the three months ended March 31, 2011, $75 million of pre-tax merger integration costs and $24 million of charges from merger settlements approved by regulatory agencies have been recognized. Charges resulting from merger settlements are not expected to be material in future periods.
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the pro forma events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| (Pro forma amounts in millions, except per share amounts) | | 2011 | | | 2010 | |
| | | | | | | | | |
| Revenues | | $ | 4,786 | | | $ | 4,685 | |
| Net income attributable to FirstEnergy | | $ | 137 | | | $ | 255 | |
| | | | | | | | | |
| Basic Earnings Per Share | | $ | 0.33 | | | $ | 0.61 | |
| | | | | | | |
| Diluted Earnings Per Share | | $ | 0.33 | | | $ | 0.61 | |
| | | | | | | |
29
3. EARNINGS PER SHARE
Basic earnings per share of common stock isare computed using the weighted average of actual common shares outstanding during the respectiverelevant 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 resultwould be issued 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:
| | | | | | | | | |
| | | Three Months Ended | |
| Reconciliation of Basic and Diluted | | March 31 | |
| Earnings per Share of Common Stock | | 2011 | | | 2010 | |
| | | (In millions, except per | |
| | | share amounts) | |
| | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 50 | | | $ | 155 | |
| | | | | | | |
| | | | | | | | | |
Weighted average number of basic shares outstanding(1) | | | 342 | | | | 304 | |
| Assumed exercise of dilutive stock options and awards | | | 1 | | | | 2 | |
| | | | | | | |
Weighted average number of diluted shares outstanding(1) | | | 343 | | | | 306 | |
| | | | | | | |
| | | | | | | | | |
| Basic earnings per share of common stock | | $ | 0.15 | | | $ | 0.51 | |
| | | | | | | |
| Diluted earnings per share of common stock | | $ | 0.15 | | | $ | 0.51 | |
| | | | | | | |
| | |
| (1) | | Includes 113 million shares issued to AE stockholders for the period subsequent to the merger date. (See Note 2, Merger) |
| | | Three Months Ended | |
| Reconciliation of Basic and Diluted Earnings per Share | | | |
| of Common Stock | | 2010 | | 2009 | |
| | | (In millions, except per share amounts) | |
| Earnings available to FirstEnergy Corp. | | $ | 155 | | $ | 119 | |
| | | | | | | | |
| Weighted average number of basic shares outstanding | | | 304 | | | 304 | |
| Assumed exercise of dilutive stock options and awards | | | 2 | | | 2 | |
| Weighted average number of diluted shares outstanding | | | 306 | | | 306 | |
| | | | | | | | |
| Basic earnings per share of common stock | | $ | 0.51 | | $ | 0.39 | |
| Diluted earnings per share of common stock | | $ | 0.51 | | $ | 0.39 | |
3.4. FAIR VALUE OF FINANCIAL INSTRUMENTS
(A) | LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS |
(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“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 March 31, 20102011 and December 31 2009:2010:
| | | | | | | | | | | | | | | | | |
| | | March 31, 2011 | | | December 31, 2010 | |
| | | Carrying | | | Fair | | | Carrying | | | Fair | |
| | | Value | | | Value | | | Value | | | Value | |
| | | (In millions) | |
FirstEnergy(1) | | $ | 18,743 | | | $ | 19,776 | | | $ | 13,928 | | | $ | 14,845 | |
| FES | | | 4,099 | | | | 4,227 | | | | 4,279 | | | | 4,403 | |
| OE | | | 1,159 | | | | 1,334 | | | | 1,159 | | | | 1,321 | |
| CEI | | | 1,831 | | | | 2,035 | | | | 1,853 | | | | 2,035 | |
| TE | | | 600 | | | | 666 | | | | 600 | | | | 653 | |
| JCP&L | | | 1,802 | | | | 1,980 | | | | 1,810 | | | | 1,962 | |
| Met-Ed | | | 742 | | | | 826 | | | | 742 | | | | 821 | |
| Penelec | | | 1,120 | | | | 1,190 | | | | 1,120 | | | | 1,189 | |
| | | | | | |
| | | Carrying | | Fair | | Carrying | | Fair | |
| | | | | | | | | | |
| | | (In millions) | |
| | | 13,581 | | | 14,373 | | | 13,753 | | | 14,502 | |
| | | 4,224 | | | 4,366 | | | 4,224 | | | 4,306 | |
| | | 1,167 | | | 1,293 | | | 1,169 | | | 1,299 | |
| | | 1,853 | | | 2,018 | | | 1,873 | | | 2,032 | |
| | | 600 | | | 639 | | | 600 | | | 638 | |
| | | 1,833 | | | 1,932 | | | 1,840 | | | 1,950 | |
| | | 742 | | | 808 | | | 842 | | | 909 | |
| | | 1,144 | | | 1,186 | | | 1,144 | | | 1,177 | |
| | |
| (1) | | Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of March 31, 2011 of $4,995 million and $5,004 million, respectively. |
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securitiesobligations 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 securitiesdebt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and the Utilities.other subsidiaries.
(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.
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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 March 31, 20102011 and December 31, 2009:2010:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31, 2011(1) | | | December 31, 2010(2) | |
| | | Cost | | | Unrealized | | | Unrealized | | | Fair | | | Cost | | | Unrealized | | | Unrealized | | | Fair | |
| | | Basis | | | Gains | | | Losses | | | Value | | | Basis | | | Gains | | | Losses | | | Value | |
| | | (In millions) | |
Debt securities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 1,985 | | | $ | 32 | | | $ | — | | | $ | 2,017 | | | $ | 1,699 | | | $ | 31 | | | $ | — | | | $ | 1,730 | |
| FES | | | 1,012 | | | | 18 | | | | — | | | | 1,030 | | | | 980 | | | | 13 | | | | — | | | | 993 | |
| OE | | | 124 | | | | 1 | | | | — | | | | 125 | | | | 123 | | | | 1 | | | | — | | | | 124 | |
| TE | | | 51 | | | | — | | | | — | | | | 51 | | | | 42 | | | | — | | | | — | | | | 42 | |
| JCP&L | | | 358 | | | | 7 | | | | — | | | | 365 | | | | 281 | | | | 9 | | | | — | | | | 290 | |
| Met-Ed | | | 240 | | | | 4 | | | | — | | | | 244 | | | | 127 | | | | 4 | | | | — | | | | 131 | |
| Penelec | | | 200 | | | | 2 | | | | — | | | | 202 | | | | 145 | | | | 4 | | | | — | | | | 149 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity securities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 186 | | | $ | 7 | | | $ | — | | | $ | 193 | | | $ | 268 | | | $ | 69 | | | $ | — | | | $ | 337 | |
| FES | | | 88 | | | | 5 | | | | — | | | | 93 | | | | — | | | | — | | | | — | | | | — | |
| TE | | | 24 | | | | 1 | | | | — | | | | 25 | | | | — | | | | — | | | | — | | | | — | |
| JCP&L | | | 21 | | | | — | | | | — | | | | 21 | | | | 80 | | | | 17 | | | | — | | | | 97 | |
| Met-Ed | | | 33 | | | | 1 | | | | — | | | | 34 | | | | 125 | | | | 35 | | | | — | | | | 160 | |
| Penelec | | | 20 | | | | — | | | | — | | | | 20 | | | | 63 | | | | 16 | | | | — | | | | 79 | |
| | |
| (1) | | Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $97 million; FES — $37 million; OE — $2 million; TE — $1 million; JCP&L — $12 million; Met-Ed — $27 million and Penelec — $18 million. |
|
| (2) | | Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy — $193 million; FES — $153 million; OE — $3 million; TE — $34 million; JCP&L — $3 million; Met-Ed — $(3) million and Penelec — $4 million. |
31
| | | March 31, 2010(1) | | December 31, 2009(2) | |
| | | Cost | | Unrealized | | Unrealized | | Fair | | Cost | | Unrealized | | Unrealized | | Fair | |
| | | Basis | | Gains | | Losses | | Value | | Basis | | Gains | | Losses | | Value | |
| Debt securities | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
(1) Excludes cash balances: FirstEnergy - $131 million; FES - $32 million; OE - $65 million; TE - $1 million; JCP&L - $15 million; Met-Ed - $(2) million and Penelec - $20 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. |
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded, and interest and dividend income for the three months ended March 31, 2011 and 2010 were as follows:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Interest and | |
| March 31, 2011 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 970 | | | $ | 100 | | | $ | (29 | ) | | $ | 24 | |
| FES | | | 216 | | | | 12 | | | | (15 | ) | | | 15 | |
| OE | | | 8 | | | | — | | | | — | | | | 1 | |
| TE | | | 14 | | | | 1 | | | | (1 | ) | | | 1 | |
| JCP&L | | | 217 | | | | 22 | | | | (4 | ) | | | 4 | |
| Met-Ed | | | 336 | | | | 43 | | | | (5 | ) | | | 2 | |
| Penelec | | | 179 | | | | 22 | | | | (4 | ) | | | 1 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Interest and | |
| March 31, 2010 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 733 | | | $ | 37 | | | $ | (51 | ) | | $ | 22 | |
| FES | | | 272 | | | | 13 | | | | (24 | ) | | | 13 | |
| OE | | | 2 | | | | — | | | | — | | | | 1 | |
| TE | | | 31 | | | | 1 | | | | (1 | ) | | | 1 | |
| JCP&L | | | 190 | | | | 8 | | | | (8 | ) | | | 4 | |
| Met-Ed | | | 144 | | | | 9 | | | | (11 | ) | | | 2 | |
| Penelec | | | 93 | | | | 6 | | | | (7 | ) | | | 1 | |
Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because 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 because 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 plans’ 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.
FirstEnergy recognized $3 million and $11 million of net realized losses for the three-month period ended March 31, 2011 and 2010, were as follows:respectively, resulting from the sale of securities held in nuclear decommissioning trusts.
| | | FirstEnergy | | FES | | OE | | TE | | JCP&L | | Met-Ed | | Penelec | |
| | | (In millions) | |
| | $ | 733 | | $ | 272 | | $ | 3 | | $ | 31 | | $ | 190 | | $ | 144 | | $ | 93 | |
| | | 36 | | | 13 | | | - | | | - | | | 8 | | | 9 | | | 6 | |
| | | 50 | | | 24 | | | - | | | - | | | 8 | | | 11 | | | 7 | |
Interest and dividend income | | | 21 | | | 13 | | | - | | | 1 | | | 4 | | | 2 | | | 1 | |
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 March 31, 20102011 and December 31, 2009 (excluding2010:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | March 31, 2011 | | | December 31, 2010 | |
| | | Cost | | | Unrealized | | | Unrealized | | | Fair | | | Cost | | | Unrealized | | | Unrealized | | | Fair | |
| | | Basis | | | Gains | | | Losses | | | Value | | | Basis | | | Gains | | | Losses | | | Value | |
| | | (In millions) | |
Debt Securities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 422 | | | $ | 79 | | | $ | — | | | $ | 501 | | | $ | 476 | | | $ | 91 | | | $ | — | | | $ | 567 | |
| OE | | | 190 | | | | 45 | | | | — | | | | 235 | | | | 190 | | | | 51 | | | | — | | | | 241 | |
| CEI | | | 287 | | | | 33 | | | | — | | | | 320 | | | | 340 | | | | 41 | | | | — | | | | 381 | |
Investments in emission allowances, employee benefits and cost method investments and equity method investments totaling $345 million as of $251March 31, 2011 and $259 million and $264 million, respectively, thatas of December 31, 2010 are not required to be disclosed):disclosed and are excluded from the amounts reported above.
32
| | | March 31, 2010 | | December 31, 2009 | |
| | | Cost | | Unrealized | | Unrealized | | Fair | | Cost | | Unrealized | | Unrealized | | Fair | |
| | | Basis | | Gains | | Losses | | Value | | Basis | | Gains | | Losses | | Value | |
| Debt securities | | (In millions) | |
| | $ | 494 | | $ | 76 | | $ | - | | $ | 570 | | $ | 544 | | $ | 72 | | $ | - | | $ | 616 | |
| | | 217 | | | 42 | | | - | | | 259 | | | 217 | | | 29 | | | - | | | 246 | |
| | | 340 | | | 33 | | | - | | | 373 | | | 389 | | | 43 | | | - | | | 432 | |
Notes Receivable
The following table below provides the approximate fair value and related carrying amounts of notes receivable as of March 31, 20102011 and December 31, 2009:
| | | | | | |
| | | Carrying | | Fair | | Carrying | | Fair | |
| | | | | | | | | | |
| Notes receivable | | (In millions) | |
| FirstEnergy | | $ | 36 | | $ | 35 | | $ | 36 | | $ | 35 | |
| FES | | | 1 | | | 1 | | | 2 | | | 1 | |
| OE | | | - | | | - | | | - | | | - | |
| | | 104 | | | 115 | | | 124 | | | 141 | |
2010. 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 20102013 to 2040.2021.
| | | | | | | | | | | | | | | | | |
| | | March 31, 2011 | | | December 31, 2010 | |
| | | Carrying | | | Fair | | | Carrying | | | Fair | |
| | | Value | | | Value | | | Value | | | Value | |
| | | (In millions) | |
Notes Receivable | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 7 | | | $ | 8 | | | $ | 7 | | | $ | 8 | |
| TE | | | 82 | | | | 94 | | | | 104 | | | | 118 | |
(C) | RECURRING FAIR VALUE MEASUREMENTS |
On January 1, 2010, FirstEnergy adopted the FASB Accounting Standards Update (Update) applicable to the Fair Value Measurements and Disclosures Topic. The Update provides amendments that require new disclosures surrounding (1) transfers of Level 1 and Level 2 fair value measurements, including the reason for transfers; (2) purchases, sales, issuances and settlements of Level 3 fair value measurements; (3) additional disaggregation of fair value measurements for each class of assets and liabilities; and (4) inputs and valuation techniques used to measure fair value for both recurring and nonrecurring fair value measurements.
(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 wherein which 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.
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 appropria teappropriate 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 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 March 31, 2010 and December 31, 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.
| | | Recurring Fair Value Measures as of March 31, 2010 | |
| | | Level 1 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Decommissioning Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities - consumer products | | $ | 136 | | $ | - | | $ | - | | $ | - | | $ | 39 | | $ | 65 | | $ | 32 | |
| Equity securities - technology | | | 59 | | | - | | | - | | | - | | | 17 | | | 28 | | | 14 | |
| Equity securities - utilities & energy | | | 59 | | | - | | | - | | | - | | | 17 | | | 28 | | | 14 | |
| Equity securities - financial | | | 48 | | | - | | | - | | | - | | | 14 | | | 23 | | | 11 | |
| Equity securities - other | | | 8 | | | - | | | - | | | - | | | 2 | | | 3 | | | 3 | |
| Total nuclear decommissioning trust investments | | $ | 310 | | $ | - | | $ | - | | $ | - | | $ | 89 | | $ | 147 | | $ | 74 | |
Total assets(1) | | $ | 310 | | $ | - | | $ | - | | $ | - | | $ | 89 | | $ | 147 | | $ | 74 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives – commodity contracts | | $ | 8 | | $ | 8 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Total liabilities | | $ | 8 | | $ | 8 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| | | Level 2 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Decommissioning Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by the U.S. government | | $ | 595 | | $ | 345 | | $ | 66 | | $ | 56 | | $ | 32 | | $ | 88 | | $ | 8 | |
| Debt securities issued by states of the U.S. | | | 90 | | | - | | | - | | | - | | | 30 | | | 1 | | | 59 | |
| Debt securities issued by foreign governments | | | 299 | | | 299 | | | - | | | - | | | - | | | - | | | - | |
| Corporate debt securities | | | 486 | | | 413 | | | 7 | | | - | | | 21 | | | 39 | | | 6 | |
| Other | | | 90 | | | 23 | | | - | | | 65 | | | 1 | | | - | | | 1 | |
| Total nuclear decommissioning trust investments | | $ | 1,560 | | $ | 1,080 | | $ | 73 | | $ | 121 | | $ | 84 | | $ | 128 | | $ | 74 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Rabbi Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities - financial | | $ | 1 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Other | | | 11 | | | - | | | - | | | 1 | | | - | | | - | | | - | |
| Total rabbi trust investments | | $ | 12 | | $ | - | | $ | - | | $ | 1 | | $ | - | | $ | - | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Fuel Disposal Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by states of the U.S. | | $ | 201 | | $ | - | | $ | - | | $ | - | | $ | 201 | | $ | - | | $ | - | |
| Other | | | 2 | | | - | | | - | | | - | | | 2 | | | - | | | - | |
| Total nuclear fuel disposal trust investments | | $ | 203 | | $ | - | | $ | - | | $ | - | | $ | 203 | | $ | - | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | |
| NUG Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by states of the U.S. | | $ | 98 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 98 | |
| Other | | | 23 | | | - | | | - | | | - | | | - | | | - | | | 23 | |
Total NUG trust investments | | $ | 121 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 121 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives | | | | | | | | | | | | | | | | | | | | | | |
| Commodity contracts | | $ | 69 | | $ | 60 | | $ | - | | $ | - | | $ | 2 | | $ | 5 | | $ | 2 | |
| Interest rate contracts | | | 2 | | | - | | | - | | | - | | | - | | | - | | | | |
Total Derivatives | | $ | 71 | | $ | 60 | | $ | - | | $ | - | | $ | 2 | | $ | 5 | | $ | 2 | |
| | | | | | | | | | | | | | | | | | | | | | | |
Total assets(1) | | $ | 1,967 | | $ | 1,140 | | $ | 73 | | $ | 122 | | $ | 289 | | $ | 133 | | $ | 197 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives | | | | | | | | | | | | | | | | | | | | | | |
| Commodity contracts | | $ | 296 | | $ | 296 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Interest rate contracts | | | 5 | | | - | | | - | | | - | | | - | | | - | | | | |
Total Derivatives | | $ | 301 | | $ | 296 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total liabilities | | $ | 301 | | $ | 296 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| | | Level 3 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
Derivatives – NUG contracts(2) | | $ | 148 | | $ | - | | $ | - | | $ | - | | $ | 6 | | $ | 137 | | $ | 5 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Derivatives – NUG contracts(2) | | $ | 738 | | $ | - | | $ | - | | $ | - | | $ | 400 | | $ | 167 | | $ | 171 | |
| (1) | Excludes $11 million of receivables, payables and accrued income.
|
(2) NUG contracts are subject to regulatory accounting and do not impact earnings.
| | | Recurring Fair Value Measures as of December 31, 2009 | |
| | | Level 1 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Decommissioning Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities - consumer products | | $ | 130 | | $ | - | | $ | - | | $ | - | | $ | 38 | | $ | 59 | | $ | 33 | |
| Equity securities - technology | | | 57 | | | - | | | - | | | - | | | 17 | | | 26 | | | 14 | |
| Equity securities - utilities & energy | | | 59 | | | - | | | - | | | - | | | 17 | | | 27 | | | 15 | |
| Equity securities - financial | | | 39 | | | - | | | - | | | - | | | 12 | | | 17 | | | 10 | |
| Equity securities - other | | | 9 | | | - | | | - | | | - | | | 3 | | | 4 | | | 2 | |
Total nuclear decommissioning trust investments(1) | | $ | 294 | | $ | - | | $ | - | | $ | - | | $ | 87 | | $ | 133 | | $ | 74 | |
| Total assets | | $ | 294 | | $ | - | | $ | - | | $ | - | | $ | 87 | | $ | 133 | | $ | 74 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives – commodity contracts | | $ | 11 | | $ | 11 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Total liabilities | | $ | 11 | | $ | 11 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| | | Level 2 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Decommissioning Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by the U.S. government | | $ | 558 | | $ | 306 | | $ | 72 | | $ | 118 | | $ | 23 | | $ | 30 | | $ | 9 | |
| Debt securities issued by states of the U.S. | | | 188 | | | 15 | | | - | | | - | | | 41 | | | 82 | | | 50 | |
| Debt securities issued by foreign governments | | | 279 | | | 279 | | | - | | | - | | | - | | | - | | | - | |
| Corporate debt securities | | | 484 | | | 443 | | | - | | | - | | | 15 | | | 20 | | | 6 | |
| Other | | | 35 | | | 29 | | | - | | | 2 | | | 1 | | | 2 | | | 1 | |
| Total nuclear decommissioning trust investments | | $ | 1,544 | | $ | 1,072 | | $ | 72 | | $ | 120 | | $ | 80 | | $ | 134 | | $ | 66 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Rabbi Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Equity securities - financial | | $ | 1 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Other | | | 9 | | | - | | | - | | | - | | | - | | | - | | | - | |
| Total rabbi trust investments | | $ | 10 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear Fuel Disposal Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by states of the U.S. | | $ | 189 | | $ | - | | $ | - | | $ | - | | $ | 189 | | $ | - | | $ | - | |
| Other | | | 11 | | | - | | | - | | | - | | | 11 | | | - | | | - | |
| Total nuclear fuel disposal trust investments | | $ | 200 | | $ | - | | $ | - | | $ | - | | $ | 200 | | $ | - | | $ | - | |
| | | | | | | | | | | | | | | | | | | | | | | |
| NUG Trust Investments | | | | | | | | | | | | | | | | | | | | | | |
| Debt securities issued by states of the U.S. | | $ | 101 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 101 | |
| Other | | | 19 | | | - | | | - | | | - | | | - | | | - | | | 19 | |
Total NUG trust investments | | $ | 120 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | 120 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives – commodity contracts | | $ | 34 | | $ | 15 | | $ | - | | $ | - | | $ | 5 | | $ | 9 | | $ | 5 | |
| Other | | | 1 | | | - | | | - | | | - | | | - | | | - | | | - | |
Total assets(1) | | $ | 1,909 | | $ | 1,087 | | $ | 72 | | $ | 120 | | $ | 285 | | $ | 143 | | $ | 191 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Derivatives – commodity contracts | | $ | 224 | | $ | 224 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| Total Liabilities | | $ | 224 | | $ | 224 | | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | |
| (1) | Excludes $21 million of receivables, payables and accrued income. |
| | | Level 3 | |
| Assets | | | FirstEnergy | | | FES | | | TE | | | OE | | | JCP&L | | | Met-Ed | | | Penelec | |
| | | | | | | | | | | | | | | | | | | | | | | |
Derivatives – NUG contracts(2) | | $ | 200 | | $ | - | | $ | - | | $ | - | | $ | 9 | | $ | 176 | | $ | 15 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
Derivatives – NUG contracts(2) | | $ | 643 | | $ | - | | $ | - | | $ | - | | $ | 399 | | $ | 143 | | $ | 101 | |
(2) NUG contracts are subject to regulatory accounting and do not impact earnings.
The determination of the above 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 liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2011 and December 31, 2010. 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. The fair value of financial assets and liabilities as of March 31, 2011 assumed in the merger with Allegheny totaled $52 million and $51 million, respectively. There were no significant transfers between Level 1, Level 2 and Level 3 as of March 31, 2011 and December 31, 2010.
33
FirstEnergy Corp.
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of March��31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 877 | | | $ | — | | | $ | 877 | |
| Derivative assets — commodity contracts | | | — | | | | 524 | | | | — | | | | 524 | |
| Derivative assets — FTRs | | | — | | | | — | | | | 1 | | | | 1 | |
| Derivative assets — interest rate swaps | | | — | | | | 4 | | | | — | | | | 4 | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 117 | | | | 117 | |
Equity securities(2) | | | 194 | | | | — | | | | — | | | | 194 | |
| Foreign government debt securities | | | — | | | | 150 | | | | — | | | | 150 | |
| U.S. government debt securities | | | — | | | | 681 | | | | — | | | | 681 | |
| U.S. state debt securities | | | — | | | | 297 | | | | — | | | | 297 | |
| | | | | | | | | | | | | |
Other(4) | | | — | | | | 148 | | | | — | | | | 148 | |
| | | | | | | | | | | | | |
Total assets | | $ | 194 | | | $ | 2,681 | | | $ | 118 | | | $ | 2,993 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
| Derivative liabilities — commodity contracts | | $ | — | | | $ | (583 | ) | | $ | — | | | $ | (583 | ) |
| Derivative liabilities — FTRs | | | — | | | | — | | | | (12 | ) | | | (12 | ) |
| Derivative liabilities — interest rate swaps | | | — | | | | (5 | ) | | | — | | | | (5 | ) |
| | | | | | | | | | | | | |
Derivative liabilities — NUG contracts(1) | | | — | | | | — | | | | (478 | ) | | | (478 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | (588 | ) | | $ | (490 | ) | | $ | (1,078 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 194 | | | $ | 2,093 | | | $ | (372 | ) | | $ | 1,915 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | NUG contracts are subject to regulatory accounting and do not impact earnings. |
|
| (2) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
|
| (3) | | Excludes $(31) million and $(7) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
|
| (4) | | Primarily consists of cash and cash equivalents. |
34
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 FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the three months endedperiods ending March 31, 2011 and December 31, 2010, and 2009 (in millions):respectively:
| | | | | | | | | | | | | |
| | | Derivative Asset(1) | | | Derivative Liability(1) | | | Net(1) | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | 122 | | | $ | (466 | ) | | $ | (344 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | (1 | ) | | | (89 | ) | | | (90 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (3 | ) | | | 77 | | | | 74 | |
| Transfers in (out) of Level 3 | | | — | | | | (12 | ) | | | (12 | ) |
| | | | | | | | | | |
| March 31, 2011 Balance | | $ | 118 | | | $ | (490 | ) | | $ | (372 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | |
| | | FirstEnergy | | JCP&L | | Met-Ed | | Penelec | |
| Balance as of January 1, 2010 | | $ | (444 | ) | $ | (391 | ) | $ | 33 | | $ | (86 | ) |
Settlements(1) | | | 78 | | | 40 | | | 17 | | | 21 | |
Unrealized losses(1) | | | (224 | ) | | (43 | ) | | (80 | ) | | (101 | ) |
| Balance as of March 31, 2010 | | $ | (590 | ) | $ | (394 | ) | $ | (30 | ) | $ | (166 | ) |
| | | | | | | | | | | | | | |
| Balance as of January 1, 2009 | | $ | (332 | ) | $ | (518 | ) | $ | 150 | | $ | 36 | |
Settlements(1) | | | 83 | | | 45 | | | 17 | | | 21 | |
Unrealized gains(1) | | | (227 | ) | | (45 | ) | | (91 | ) | | (91 | ) |
| Balance as of March 31, 2009 | | $ | (476 | ) | $ | (518 | ) | $ | 76 | | $ | (34 | ) |
| | | | | | | | | | | | | | |
(1) | | |
| (1) | | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
FirstEnergy Solutions Corp.
The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 567 | | | $ | — | | | $ | 567 | |
| Derivative assets — commodity contracts | | | — | | | | 476 | | | | — | | | | 476 | |
| Derivative assets — FTRs | | | — | | | | — | | | | 1 | | | | 1 | |
Equity securities(3) | | | 93 | | | | — | | | | — | | | | 93 | |
| Foreign government debt securities | | | — | | | | 148 | | | | — | | | | 148 | |
| U.S. government debt securities | | | — | | | | 304 | | | | — | | | | 304 | |
| | | | | | | | | | | | | |
| U.S. state debt securities | | | — | | | | 8 | | | | — | | | | 8 | |
Other(2) | | | — | | | | 43 | | | | — | | | | 43 | |
| | | | | | | | | | | | | |
Total assets | | $ | 93 | | | $ | 1,546 | | | $ | 1 | | | $ | 1,640 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
| Derivative liabilities — commodity contracts | | $ | — | | | $ | (549 | ) | | $ | — | | | $ | (549 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | (549 | ) | | $ | — | | | $ | (549 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(1) | | $ | 93 | | | $ | 997 | | | $ | 1 | | | $ | 1,091 | |
| | | | | | | | | | | | | |
35
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Excludes $(3) million and $7 million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
|
| (2) | | Primarily consists of cash and cash equivalents. |
|
| (3) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the period ending March 31, 2011:
| | | | | | | | | | | | | |
| | | Derivative Asset | | | Derivative Liability | | | Net | |
| | | FTRs | | | FTRs | | | FTRs | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | — | | | $ | — | | | $ | — | |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | 1 | | | | — | | | | 1 | |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | — | | | | — | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| March 31, 2011 Balance | | $ | 1 | | | $ | — | | | $ | 1 | |
| | | | | | | | | | |
Ohio Edison Company
The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| U.S. government debt securities | | $ | — | | | $ | 125 | | | $ | — | | | $ | 125 | |
| Other | | | — | | | | 6 | | | | — | | | | 6 | |
| | | | | | | | | | | | | |
Total assets(1) | | $ | — | | | $ | 131 | | | $ | — | | | $ | 131 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Excludes $(3) million and $1 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
36
Toledo Edison Company
The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | |
Equity securities(3) | | | 25 | | | | — | | | | — | | | | 25 | |
| U.S. government debt securities | | | — | | | | 32 | | | | — | | | | 32 | |
| U.S. state debt securities | | | — | | | | 2 | | | | — | | | | 2 | |
Other(2) | | | — | | | | 3 | | | | — | | | | 3 | |
| | | | | | | | | | | | | |
Total assets(1) | | $ | 25 | | | $ | 53 | | | $ | — | | | $ | 78 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Excludes $(1) million and $2 million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
|
| (2) | | Primarily consists of cash and cash equivalents. |
|
| (3) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
Jersey Central Power & Light Company
The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 92 | | | $ | — | | | $ | 92 | |
| Derivative assets — commodity contracts | | | — | | | | — | | | | — | | | | — | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 6 | | | | 6 | |
Equity securities(2) | | | 21 | | | | — | | | | — | | | | 21 | |
| Foreign government debt securities | | | — | | | | 1 | | | | — | | | | 1 | |
| U.S. government debt securities | | | — | | | | 60 | | | | — | | | | 60 | |
| U.S. state debt securities | | | — | | | | 214 | | | | — | | | | 214 | |
| | | | | | | | | | | | | |
| Other | | | — | | | | 16 | | | | — | | | | 16 | |
| | | | | | | | | | | | | |
Total assets | | $ | 21 | | | $ | 383 | | | $ | 6 | | | $ | 410 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities – NUG contracts(1) | | $ | — | | | $ | — | | | $ | (239 | ) | | $ | (239 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (239 | ) | | $ | (239 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 21 | | | $ | 383 | | | $ | (233 | ) | | $ | 171 | |
| | | | | | | | | | | | | |
37
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | NUG contracts are subject to regulatory accounting and do not impact earnings. |
|
| (2) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
|
| (3) | | Excludes $(8) million and $(3) million as of March 31, 2011 and December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts are subject to regulatory accountingheld by JCP&L and do not impact earnings.classified as Level 3 in the fair value hierarchy for the periods ending March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | |
| | | Derivative Asset | | | Derivative Liability | | | Net | |
| | | NUG Contracts(1) | | | NUG Contracts(1) | | | NUG Contracts(1) | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | 6 | | | $ | (233 | ) | | $ | (227 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | — | | | | (42 | ) | | | (42 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | 36 | | | | 36 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| March 31, 2011 Balance | | $ | 6 | | | $ | (239 | ) | | $ | (233 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | |
4. | | |
| (1) | | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
38
Metropolitan Edison Company
The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 131 | | | $ | — | | | $ | 131 | |
| Derivative assets — commodity contracts | | | — | | | | — | | | | — | | | | — | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 107 | | | | 107 | |
Equity securities(2) | | | 34 | | | | — | | | | — | | | | 34 | |
| Foreign government debt securities | | | — | | | | 2 | | | | — | | | | 2 | |
| U.S. government debt securities | | | — | | | | 100 | | | | — | | | | 100 | |
| U.S. state debt securities | | | — | | | | 2 | | | | — | | | | 2 | |
| Other | | | — | | | | 37 | | | | — | | | | 37 | |
| | | | | | | | | | | | | |
Total assets | | $ | 34 | | | $ | 272 | | | $ | 107 | | | $ | 413 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities – NUG contracts(1) | | $ | — | | | $ | — | | | $ | (118 | ) | | $ | (118 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (118 | ) | | $ | (118 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 34 | | | $ | 272 | | | $ | (11 | ) | | $ | 295 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | NUG contracts are subject to regulatory accounting and do not impact earnings. |
|
| (2) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
|
| (3) | | Excludes $(1) million and $(9) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table. |
39
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 periods ending March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | |
| | | Derivative Asset | | | Derivative Liability | | | Net | |
| | | NUG Contracts(1) | | | NUG Contracts(1) | | | NUG Contracts(1) | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | 112 | | | $ | (116 | ) | | $ | (4 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | (2 | ) | | | (16 | ) | | | (18 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (3 | ) | | | 14 | | | | 11 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| March 31, 2011 Balance | | $ | 107 | | | $ | (118 | ) | | $ | (11 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | |
| | |
| (1) | | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
Pennsylvania Electric Company
The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| March 31, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 70 | | | $ | — | | | $ | 70 | |
| Derivative assets — commodity contracts | | | — | | | | — | | | | — | | | | — | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 4 | | | | 4 | |
Equity securities(2) | | | 20 | | | | — | | | | — | | | | 20 | |
| Foreign government debt securities | | | — | | | | — | | | | — | | | | — | |
| U.S. government debt securities | | | — | | | | 60 | | | | — | | | | 60 | |
| U.S. state debt securities | | | — | | | | 72 | | | | — | | | | 72 | |
| | | | | | | | | | | | | |
| Other | | | — | | | | 32 | | | | — | | | | 32 | |
| | | | | | | | | | | | | |
Total assets | | $ | 20 | | | $ | 234 | | | $ | 4 | | | $ | 258 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities – NUG contracts(1) | | $ | — | | | $ | — | | | $ | (122 | ) | | $ | (122 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (122 | ) | | $ | (122 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 20 | | | $ | 234 | | | $ | (118 | ) | | $ | 136 | |
| | | | | | | | | | | | | |
40
| | | | | | | | | | | | | | | | | |
| 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 | |
| | | | | | | | | | | | | |
| | |
| (1) | | NUG contracts are subject to regulatory accounting and do not impact earnings. |
|
| (2) | | NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index. |
|
| (3) | | Excludes $(15) million and $(3) million as of March 31, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
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 periods ended March 31, 2011 and December 31, 2010:
| | | | | | | | | | | | | |
| | | Derivative Asset | | | Derivative Liability | | | Net | |
| | | NUG Contracts(1) | | | NUG Contracts(1) | | | NUG Contracts(1) | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | 4 | | | $ | (117 | ) | | $ | (113 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | — | | | | (30 | ) | | | (30 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | 25 | | | | 25 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| March 31, 2011 Balance | | $ | 4 | | | $ | (122 | ) | | $ | (118 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | |
| | |
| (1) | | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
41
5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy usesestablished 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, which 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.
practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchasepurchases and normal sales criteria. Derivatives that meet those criteria are accounted for at cost under the accrual method of accounting. The changesaccounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that do not meetqualify and are designated as cash flow hedge instruments are recorded to AOCL. Change in the normal purchase 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 thefair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in the hedged item. A hypothetical 10% adverse shift (an increase or decrease dependingincome statement on a mark-to-market basis. FirstEnergy’s has contractual derivative agreements through December 2018.
Cash Flow Hedges
FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on the derivative position) in quoted market pricescontract are reported as a component of AOCL with subsequent reclassification to earnings in the near term on itsperiod during which the hedged forecasted transaction affects earnings.
As of December 31, 2010, commodity derivative instruments would not have had a material effect on FirstEnergy’s consolidated financial position (assets, liabilitiescontracts designated in cash flow hedging relationships were $104 million of assets and equity) or$101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash f lowsflow hedge relationships. Total net unamortized losses included in AOCL associated with dedesignated cash flow hedges totaled $6 million as of March 31, 2010. Based on derivative contracts held as2011. Since the forecasted transactions remain probable of occurring, these amounts were “frozen” in AOCL and will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expense totaled $5 million for the three-months ended March 31, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $42011. Approximately $16 million will be amortized to earnings as expense during the next 12twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by approximately $2 million for the three months ended March 31, 2010.
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. During the first three monthsAs of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income andMarch 31, 2011, no forward starting swap agreements were outstanding as of March 31, 2010.
The table below provides the activity of AOCL related to interest rate cash flow hedges as of March 31, 2010 and 2009, which is inclusive of changes in fair value of interest rate cash flow hedges and the reclassification from AOCL into results of operations.
| | | | Three Months Ended | |
| | | | March 31 | |
| | | | 2010 | | 2009 | |
| | | (In millions) | |
| Effective Portion | | | | | | | |
| | Loss Recognized in AOCL | | $ | - | | $ | (2 | ) |
| | Reclassifications from AOCL into Interest Expense | | | (3 | ) | | (5 | ) |
outstanding. Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $101$87 million ($6357 million net of tax) as of March 31, 2010.2011. Based on current estimates, approximately $11$10 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3 million for the three-months ended March 31, 2011 and 2010.
Fair Value Hedges
FirstEnergy useshas 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 are 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 debtderivative instruments due to lower interest rates. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2010, the debt underlying the $950 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 3.74%. The gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attri butable to the hedged risk are recognized in earnings. As of March 31, 2010, the gain included in interest expense related to interest rate swaps totaled $1 million and there was no impact on the results of operations as a result of ineffectiveness from fair value hedges.
The following tables summarize the fair value of interest rate swaps in FirstEnergy’s Consolidated Balance Sheets:
| | | Derivative Assets | | | | Derivative Liabilities |
| | | Fair Value | | | | Fair Value |
| | | March 31 | | December 31 | | | | March 31 | | December 31 |
| | | 2010 | | 2009 | | | | 2010 | | 2009 |
| Fair Value Hedges | | (In millions) | | Fair Value Hedges | | (In millions) |
| Interest Rate Swaps | | | | | | Interest Rate Swaps | | | | |
| Noncurrent Assets | $ | 2 | $ | - | | | Noncurrent Assets | $ | 5 | $ | - |
| | $ | 2 | $ | - | | | $ | 5 | $ | - |
On April 29, 2010, April 30, 2010 and May 3, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with combined notional amounts of $1.3 billion, $300 million and $600 million, respectively, to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. This is consistent with FirstEnergy’s risk management policy and its 2010 financial plan. These derivatives will bewere 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 May 3,March 31, 2011, no fixed-for-floating interest rate swap agreements were outstanding.
As of March 31, 2010, the debt underlying the $2.2 billion outstandingFirstEnergy held fixed-for-floating interest rate swap agreements with combined notional amountamounts of $950 million. The gains included in interest expense related to interest rate swaps hadtotaled $1 million and the fair value of the derivative instruments totaled $(3) million. There was no impact on the results of operations as a weighted average fixedresult of ineffectiveness from fair value hedges.
Total unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $118 million ($77 million net of 6%, whichtax) as of March 31, 2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the swaps have converted to a current weighted avera ge variable rate of 3.4%.
next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $5 million and $1 million for the three-months ended March 31, 2011 and 2010, respectively.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.
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The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:
| Derivative Assets | | Derivative Liabilities |
| | | Fair Value | | | | Fair Value |
| | | March 31 | | December 31 | | | | March 31 | | December 31 |
| | | 2010 | | 2009 | | | | 2010 | | 2009 |
| Cash Flow Hedges | | (In millions) | | Cash Flow Hedges | | (In millions) |
| Electricity Forwards | | | | | | Electricity Forwards | | | | |
| Current Assets | $ | 39 | $ | 3 | | Current Liabilities | $ | 39 | $ | 7 |
| Noncurrent Assets | | 19 | | 11 | | Noncurrent Liabilities | | 26 | | 12 |
| Natural Gas Futures | | | | | | Natural Gas Futures | | | | |
| Current Assets | | - | | - | | Current Liabilities | | 7 | | 9 |
| Noncurrent Assets | | - | | - | | Noncurrent Liabilities | | - | | - |
| Other | | | | | | Other | | | | |
| Current Assets | | - | | - | | Current Liabilities | | 1 | | 2 |
| Noncurrent Assets | | - | | - | | Noncurrent Liabilities | | - | | - |
| | $ | 58 | $ | 14 | | | $ | 73 | $ | 30 |
| | | | | | | | | | | |
| | | | | | | |
| Derivative Assets | | Derivative Liabilities |
| | | Fair Value | | | | Fair Value |
| | | March 31 2010 | | December 31 2009 | | | | March 31 2010 | | December 31 2009 |
| Economic Hedges | | (In millions) | | Economic Hedges | | (In millions) |
| NUG Contracts | | | | NUG Contracts | | |
| Power Purchase | | | | | | Power Purchase | | | | |
| Contract Asset | $ | 148 | $ | 200 | | Contract Liability | $ | 738 | $ | 643 |
| Other | | | | | | Other | | | | |
| Current Assets | | 1 | | - | | Current Liabilities | | 139 | | 106 |
| Noncurrent Assets | | 10 | | 19 | | Noncurrent Liabilities | | 92 | | 97 |
| | $ | 159 | $ | 219 | | | $ | 969 | $ | 846 |
| Total Commodity Derivatives | $ | 217 | $ | 233 | | Total Commodity Derivatives | $ | 1,042 | $ | 876 |
Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily natural gas 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. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.
As of March 31, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $59 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $120 million and Allegheny posted $1 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $24 million of additional collateral if the credit rating for its debt were to fall below investment grade.
Based on derivative contracts held as of March 31, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $12 million ($7 million net of tax) during the next twelve months.
FTRs
FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. These future obligations are reflected on the Consolidated Balance Sheets; and have not been designated as cash flow hedge instruments. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of auction revenue rights allocated to members of an RTO that have load serving obligations. FirstEnergy initially records FTRs at the FTR auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities.
The following tables summarize the fair value of derivative instruments in FirstEnergy’s Consolidated Balance Sheets:
Derivatives not designated as hedging instruments as of March 31, 2011:
| | | | | | | | | |
| Derivative Assets | |
| | | Fair Value | |
| | | March 31, | | | December 31, | |
| | | 2011 | | | 2010 | |
| | | (In millions) | |
| | | | | | | | | |
| Power Contracts | | | | | | | | |
| Current Assets | | $ | 332 | | | $ | 151 | |
| Noncurrent Assets | | | 192 | | | | 89 | |
| FTRs | | | | | | | | |
| Current Assets | | | 1 | | | | — | |
| Noncurrent Assets | | | — | | | | — | |
| NUGs | | | | | | | | |
| Current Assets | | | 3 | | | | 3 | |
| Noncurrent Assets | | | 114 | | | | 119 | |
| Interest Rate Swaps | | | | | | | | |
| Current Assets | | | 4 | | | | — | |
| Noncurrent Assets | | | — | | | | — | |
| Other | | | | | | | | |
| Current Assets | | | — | | | | 10 | |
| Noncurrent Assets | | | — | | | | — | |
| | | | | | | |
| Total Derivatives | | $ | 646 | | | $ | 372 | |
| | | | | | | |
| | | | | | | | | |
| Derivative Liabilities | |
| | | Fair Value | |
| | | March 31, | | | December 31, | |
| | | 2011 | | | 2010 | |
| | | (In millions) | |
| | | | | | | | | |
| Power Contracts | | | | | | | | |
| Current Liabilities | | $ | 408 | | | $ | 266 | |
| Noncurrent Liabilities | | | 175 | | | | 81 | |
| FTRs | | | | | | | | |
| Current Liabilities | | | 12 | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| NUGs | | | | | | | | |
| Current Liabilities | | | 277 | | | | 229 | |
| Noncurrent Liabilities | | | 202 | | | | 238 | |
| Interest Rate Swaps | | | | | | | | |
| Current Liabilities | | | 5 | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| Other | | | | | | | | |
| Current Liabilities | | | — | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| | | | | | | |
| Total Derivatives | | $ | 1,079 | | | $ | 814 | |
| | | | | | | |
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The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2010:2011:
| | Purchases | | Sales | | Net | | | Units | |
| | (In thousands) | |
| Electricity Forwards | | 19,104 | | | (11,924) | | | 7,180 | | | MWH | |
| Heating Oil Futures | | 3,360 | | | - | | | 3,360 | | | Gallons | |
| Natural Gas Futures | | 2,000 | | | (1,500) | | | 500 | | | mmBtu | |
| | | | | | | | | | | | | | | | | |
| | | Purchases | | | Sales | | | Net | | | Units |
| | | (In thousands) | |
| Power Contracts | | | 83,603 | | | | (100,407 | ) | | | (16,804 | ) | | MWH |
| FTRs | | | 18,199 | | | | (130 | ) | | | 18,069 | | | MWH |
| Interest Rate Swaps | | | 200,000 | | | | (200,000 | ) | | | — | | | notional dollars |
| NUGs | | | 29,824 | | | | — | | | | 29,824 | | | MWH |
The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months ended March 31, 20102011 and 2009, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively,2010, are summarized in the following tables:
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended March 31, | |
| | | Power | | | | | | | Interest | | | | | | | |
| | | Contracts | | | FTRs | | | Rate Swaps | | | Other | | | Total | |
| | | (In millions) | |
Derivatives in a Hedging Relationship | | | | | | | | | | | | | | | | | | | | |
2011 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | (9 | ) | | $ | — | | | $ | — | | | | — | | | $ | (9 | ) |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | 14 | | | | — | | | | — | | | | — | | | | 14 | |
| Wholesale Revenue | | | (3 | ) | | | — | | | | — | | | | — | | | | (3 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | (2 | ) | | | — | | | | — | | | | 3 | | | $ | 1 | |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | 2 | | | | — | | | | — | | | | — | | | | 2 | |
| Fuel Expense | | | — | | | | — | | | | — | | | | 4 | | | | 4 | |
| | | | | | | | | | | | | | | | | | | | | |
Derivatives Not in a Hedging Relationship | | | | | | | | | | | | | | | | | | | | |
2011 | | | | | | | | | | | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | $ | 29 | | | | — | | | | — | | | | — | | | $ | 29 | |
| Wholesale Revenue | | | — | | | | — | | | | — | | | | — | | | | — | |
| Other Operating Expense | | | (20 | ) | | | 1 | | | | — | | | | — | | | | (19 | ) |
| |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (19 | ) | | | (2 | ) | | | — | | | | — | | | | (21 | ) |
| Wholesale Revenue | | | (2 | ) | | | — | | | | (1 | ) | | | — | | | | (3 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | | | | | | | | | | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | $ | (27 | ) | | | — | | | | — | | | | — | | | $ | (27 | ) |
| |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (25 | ) | | | — | | | | — | | | | — | | | | (25 | ) |
| | Three Months Ended March 31, | |
| Derivatives in Cash Flow Hedging Relationships | | Electricity | | | Natural Gas | | | Heating Oil | | | | |
| | | Forwards | | | Futures | | | Futures | | | Total | |
| 2010 | | (in millions) | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (5 | ) | $ | (1 | ) | $ | - | | $ | (6 | ) |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | |
| Purchased Power Expense | | (4 | ) | | - | | | - | | | (4 | ) |
| Fuel Expense | | - | | | (3 | ) | | (1 | ) | | (4 | ) |
| | | | | | | | | | | | | |
| 2009 | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (2 | ) | $ | (7 | ) | $ | (1 | ) | $ | (10 | ) |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | |
| Purchased Power Expense | | (18 | ) | | - | | | - | | | (18 | ) |
| Fuel Expense | | - | | | - | | | (4 | ) | | (4 | ) |
| | | | | | | | | | | | | |
(1) The ineffective portion was immaterial. | |
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| | | | | | | | | | | | | |
| Derivatives Not in a Hedging | | Three Months Ended March 31, | |
| Relationship with Regulatory Offset(2) | | NUGs | | | Other | | | Total | |
| | | (In millions) | |
2011 | | | | | | | | | | | | |
| Unrealized Loss to NUG Liability: | | $ | (89 | ) | | $ | — | | | $ | (89 | ) |
| Unrealized Gain to Regulatory Assets: | | | 89 | | | | — | | | | 89 | |
| | | | | | | | | | | | | |
| Realized Gain to NUG Liability: | | | 72 | | | | — | | | | 72 | |
| Realized Loss to Regulatory Assets: | | | (72 | ) | | | — | | | | (72 | ) |
| Realized Loss to Deferred Charges | | | — | | | | (10 | ) | | | (10 | ) |
| Realized Gain to Regulatory Assets: | | | — | | | | 10 | | | | 10 | |
| | | | | | | | | | | | | |
2010 | | | | | | | | | | | | |
| Unrealized Loss to NUG Liability: | | $ | (224 | ) | | | — | | | $ | (224 | ) |
| Unrealized Gain to Regulatory Assets: | | | 224 | | | | — | | | | 224 | |
| |
| Realized Gain to NUG Liability: | | | 78 | | | | — | | | | 78 | |
| Realized Loss to Regulatory Assets: | | | (78 | ) | | | — | | | | (78 | ) |
| Realized Loss to Deferred Charges | | | — | | | | (9 | ) | | | (9 | ) |
| Realized Gain to Regulatory Assets: | | | — | | | | 9 | | | | 9 | |
| | |
| (1) | | The ineffective portion was immaterial. |
|
| (2) | | Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers. |
| | | Three Months Ended March 31, | |
| Derivatives Not in Hedging Relationships | | | NUG | | | | | | | |
| | | | Contracts | | | Other | | | Total | |
| 2010 | | | (In millions) | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | |
| Purchase Power Expense | | $ | - | | $ | (52 | ) | $ | (52 | ) |
Regulatory Assets(2) | | | (224 | ) | | - | | | (224 | ) |
| | | $ | (224 | ) | $ | (52 | ) | $ | (276 | ) |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
| Purchase Power Expense | | $ | - | | $ | (25 | ) | $ | (25 | ) |
Regulatory Assets(2) | | | (78 | ) | | 9 | | | (69 | ) |
| | | $ | (78 | ) | $ | (16 | ) | $ | (94 | ) |
| 2009 | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | |
Regulatory Assets(2) | | $ | (227 | ) | $ | - | | $ | (227 | ) |
| | | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
Fuel Expense(1) | | $ | - | | $ | (1 | ) | $ | (1 | ) |
Regulatory Assets(2) | | | (83 | ) | | 10 | | | (73 | ) |
| | | $ | (83 | ) | $ | 9 | | $ | (74 | ) |
| | | | | | | | | | | |
| (1) | The realized gain (loss) is reclassified upon termination of the derivative instrument. | |
| (2) | Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers. | |
Total unamortized losses includedThe following table provides a reconciliation of changes in AOCL associated with commodity derivatives were $14 million ($9 million net of tax) as of March 31, 2010, as compared to $32 million ($19 million net of tax) as of March 31, 2009. The net of tax change resulted from a net $5 million increase related to current hedging activity and a $5 million decrease due to net hedge losses reclassified to earnings during the first quarter of 2010. Based on current estimates, approximately $5 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 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 fluctuate from period to period based on various market factors.
Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2010, FirstEnergy posted $225 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivativecertain contracts include credit risk-related contingent features that would require FirstEnergy 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 are in a liability position on March 31, 2010 was $245 million,deferred for which $225 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $40 million of additional collateral related to commodity derivatives.future recover from (or refund to) customers.
| | | | | | | | | | | | | |
| | | Three Months Ended March 31, | |
| Derivatives Not in a Hedging Relationship with Regulatory Offset(1) | | NUGs | | | Other | | | Total | |
| | | (In millions) | |
| Outstanding net asset (liability) as of January 1, 2011 | | $ | (345 | ) | | $ | 10 | | | $ | (335 | ) |
| Additions/Change in value of existing contracts | | | (89 | ) | | | — | | | | (89 | ) |
| Settled contracts | | | 72 | | | | (10 | ) | | | 62 | |
| | | | | | | | | | |
| Outstanding net asset (liability) as of March 31, 2011 | | $ | (362 | ) | | $ | — | | | $ | (362 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Outstanding net asset (liability) as of January 1, 2010 | | $ | (444 | ) | | $ | 19 | | | $ | (425 | ) |
| Additions/Change in value of existing contracts | | | (224 | ) | | | — | | | | (224 | ) |
| Settled contracts | | | 78 | | | | (9 | ) | | | 69 | |
| | | | | | | | | | |
| Outstanding net asset (liability) as of March 31, 2010 | | $ | (590 | ) | | $ | 10 | | | $ | (580 | ) |
| | | | | | | | | | |
| | |
| (1) | | Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers. |
5.6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover 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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
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FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the first quarter of 2011, FirstEnergy made a $157 million contribution to its qualified pension plans. FirstEnergy intends to make additional contributions of $220 million and $6 million to its qualified pension plans and postretirement benefit plans, respectively, in the last three quarters of 2011.
FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. As a result of the fair value measurement, FirstEnergy recorded accumulated benefit obligation reductions to the Allegheny pension plans and postretirement benefits other than pensions in the amount of $6 million and $2 million, respectively. The expected returns on plan assets used to calculate net period costs for the month ended March 31, 2011 was 8.25% for the Allegheny qualified pension plan and 5.00% for the Allegheny postretirement benefit plans other than pension plans.
The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans at that date were $1,341 million and $272 million, respectively.
FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended March 31, 2011 and 2010 and 2009 were $24$28 million and $43$24 million, respectively. The components of FirstEnergy'sFirstEnergy’s net pension and other postretirement benefit costsOPEB (including amounts capitalized) for the three months ended March 31,30, 2011 and 2010, and 2009, consisted of the following:
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| Pension Benefit Cost (Credit) | | 2011 | | | 2010 | |
| | | (In millions) | |
| Service cost | | $ | 29 | | | $ | 25 | |
| Interest cost | | | 84 | | | | 78 | |
| Expected return on plan assets | | | (102 | ) | | | (90 | ) |
| Amortization of prior service cost | | | 4 | | | | 3 | |
| Recognized net actuarial loss | | | 49 | | | | 47 | |
Curtailments (1) | | | (2 | ) | | | — | |
Special termination benefits (1) | | | 9 | | | | — | |
| | | | | | | |
| Net periodic cost | | $ | 71 | | | $ | 63 | |
| | | | | | | |
| | |
| (1) | | Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger. |
| | | Three Months Ended | | | | | | | | | |
| | | March 31 | | | Three Months Ended | |
| Pension Benefits | | 2010 | | 2009 | | |
| | | | March 31 | |
| Other Postretirement Benefit Cost (Credit) | | | 2011 | | 2010 | |
| | | (In millions) | | | (In millions) | |
| Service cost | | $ | 25 | | $ | 22 | | | $ | 3 | | $ | 2 | |
| Interest cost | | | 78 | | | 80 | | | 11 | | 11 | |
| Expected return on plan assets | | | (90 | ) | | (81 | ) | | | (10 | ) | | | (9 | ) |
| Amortization of prior service cost | | | 3 | | | 3 | | | | (48 | ) | | | (48 | ) |
| Recognized net actuarial loss | | | 47 | | | 42 | | | 14 | | 15 | |
| | | | | | | |
| Net periodic cost | | $ | 63 | | $ | 66 | | | $ | (30 | ) | | $ | (29 | ) |
| | | | | | | |
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| | | Three Months Ended | |
| | | March 31 | |
| Other Postretirement Benefits | | 2010 | | 2009 | |
| | | (In millions) | |
| Service cost | | $ | 2 | | $ | 5 | |
| Interest cost | | | 11 | | | 20 | |
| Expected return on plan assets | | | (9 | ) | | (9 | ) |
| Amortization of prior service cost | | | (48 | ) | | (38 | ) |
| Recognized net actuarial loss | | | 15 | | | 16 | |
| Net periodic credit | | $ | (29 | ) | $ | (6 | ) |
Pension and other postretirement benefit obligations are allocated to FirstEnergy'sFirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic other postretirement benefit costs (including amounts capitalized) recognized by FES and each of the UtilitiesFirstEnergy’s subsidiaries for the three months ended March 31, 20102011 and 20092010 were as follows:
| | | | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| Pension Benefit Cost (Credit) | | 2011 | | | 2010 | |
| | | (In millions) | |
| FES | | $ | 22 | | | $ | 22 | |
| OE | | | 5 | | | | 6 | |
| CEI | | | 5 | | | | 5 | |
| TE | | | 1 | | | | 2 | |
| JCP&L | | | 5 | | | | 6 | |
| Met-Ed | | | 3 | | | | 2 | |
| Penelec | | | 5 | | | | 5 | |
| Other FirstEnergy Subsidiaries | | | 25 | | | | 15 | |
| | | | | | | |
| | | $ | 71 | | | $ | 63 | |
| | | | | | | |
| | | Three Months Ended | | | | | | | | | |
| | | March 31 | | | Three Months Ended | |
| Pension Benefit Cost | | 2010 | | 2009 | | |
| | | | March 31 | |
| Other Postretirement Benefit Cost (Credit) | | | 2011 | | 2010 | |
| | | (In millions) | | | (In millions) | |
| FES | | $ | 22 | | $ | 18 | | | $ | (6 | ) | | $ | (7 | ) |
| OE | | | 6 | | | 7 | | | | (6 | ) | | | (6 | ) |
| CEI | | | 5 | | | 5 | | | | (2 | ) | | | (1 | ) |
| TE | | | 2 | | | 2 | | | — | | | (1 | ) |
| JCP&L | | | 6 | | | 9 | | | | (2 | ) | | | (2 | ) |
| Met-Ed | | | 2 | | | 6 | | | | (3 | ) | | | (2 | ) |
| Penelec | | | 5 | | | 4 | | | | (3 | ) | | | (2 | ) |
| Other FirstEnergy subsidiaries | | | 15 | | | 15 | | |
| Other FirstEnergy Subsidiaries | | | | (8 | ) | | | (8 | ) |
| | | $ | 63 | | $ | 66 | | | | | | |
| | | | $ | (30 | ) | | $ | (29 | ) |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
| Other Postretirement Benefit Cost (Credit) | | 2010 | | 2009 | |
| | | (In millions) | |
| FES | | $ | (7 | ) | $ | (1 | ) |
| OE | | | (6 | ) | | (2 | ) |
| CEI | | | (1 | ) | | 1 | |
| TE | | | (1 | ) | | 1 | |
| JCP&L | | | (2 | ) | | (1 | ) |
| Met-Ed | | | (2 | ) | | (1 | ) |
| Penelec | | | (2 | ) | | - | |
| Other FirstEnergy subsidiaries | | | (8 | ) | | (3 | ) |
| | | $ | (29 | ) | $ | (6 | ) |
6.7. 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 analysisanalyses 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 impact 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 re quired for determining whether an entity is the primary beneficiary. There was no impact to FirstEnergy or its subsidiaries as a result of the adoption of this standard.
VIE’s included in FirstEnergy’s consolidated financial statements includeare: FEV’s joint venture in the accountsSignal 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 entities inJCP&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 it has a controlling financial interest. $302 million was outstanding as of March 31, 2011.
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 within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($65 million) and distributions to owners ($3 million).
FirstEnergy has financial control through disproportionate economics in its equity investments and loans to certain VIEs, which include FEV’s joint venture in for 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 $333 million was outstanding as ofthree months ended March 31, 2010. As a result, FirstEnergy consolidates these VIEs.
2011.
In order to evaluate contracts under thefor consolidation guidance,treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated contractsvariable interests into twothe following categories based on similar risk characteristics and significance as follows:
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PATH-WV
PATH, LLC was formed to construct, through its operating companies, a portion of the PATH Project, which is a high-voltage transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.
Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was $26 million at March 31, 2011.
Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the Utilities andif the contract price for power is correlated with the plant'splant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and Penelec,MP, maintains 2023 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978.PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but twofour of these NUG entities, neither JCP&L, nor Met-Ed nor Penelecits subsidiaries do not have variable interests in the entities or the entities are governmental or not-for-profit organizationsdo not withinmeet the scope of consolidation consideration for VIEs.criteria to be considered a VIE. JCP&L, PE and WP 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,four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
SinceBecause JCP&L, hasPE and WP have no equity or debt interests in the NUG entities, itstheir maximum exposure to loss relates primarily to the above-market costs it incursincurred for power. FirstEnergy expects any above-market costs it incursincurred by its subsidiaries to be recovered from customers. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended March 31, 2011, were $65 million, $11 million and $5 million for JCP&L, PE and WP, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were $65 million and $67 million forheld by JCP&L during the three months ended March 31, 2010 were $64 million.
In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of March 31, 2011, WP’s reserve for this adverse purchase power commitment was $61 million, including a current liability of $18 million, and 2009, respectively.is being amortized over the life of the commitment.
Loss Contingencies
FirstEnergy has variable interests in certain sale-leaseback transactions. FirstEnergy concluded that it 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.events. 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.events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company'scompany’s net exposure to loss based upon the casualty value provisions mentioned above:above as of March 31, 2011:
| | | | | | | | | | | | | |
| | | Maximum | | | Discounted Lease | | | Net | |
| | | Exposure | | | Payments, net(1) | | | Exposure | |
| | | (In millions) | |
| FES | | $ | 1,376 | | | $ | 1,187 | | | $ | 189 | |
| OE | | | 644 | | | | 485 | | | | 159 | |
CEI(2) | | | 664 | | | | 68 | | | | 596 | |
TE(2) | | | 664 | | | | 351 | | | | 313 | |
| | | Maximum Exposure | | Discounted Lease Payments, net(1) | | Net Exposure |
| | | (In millions) |
| FES | | $ | 1,372 | | $ | 1,195 | | $ | 177 |
| OE | | 702 | | 538 | | 164 |
CEI(2) | | 702 | | 69 | | 633 |
TE(2) | | 702 | | 385 | | 317 |
(1) | | |
| (1) | | The net present value of FirstEnergy'sFirstEnergy’s consolidated sale andleaseback operating lease commitments is $1.7 billion. |
| |
| (2) | | CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements. |
7.8. INCOME TAXES
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'scompany’s tax return. As a result of the merger with Allegheny in the first quarter of 2011, FirstEnergy’s unrecognized tax benefits increased by $97 million. There were no other material changes to FirstEnergy’s unrecognized tax benefits during the first three months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs in the first quarter of 2010, FirstEnergy reduced the amount of unrecognized tax benefits by $57 million, 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 this tax item forin the first three months of 2010. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million i n tax benefits, which favorably affected FirstEnergy's effective tax rate.
As of March 31, 2010,2011, it is reasonably possible that approximately $107$48 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $12$6 million, if recognized, would affect FirstEnergy'sFirstEnergy’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 gains and losses recognized on the disposition of assets and various otherstate tax items.
The CompanyFirstEnergy 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. During the first three months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest from Allegheny. The reversal of accrued interest associated with the $57 million in recognized tax benefits in 2010 favorably affected FirstEnergy’s effective tax rate by $5 million in the first quarter of 2010. During the first three months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of March 31, 20102011 was $20$10 million, as compared to $21 mil lionwith $3 million as of December 31, 2009.2010.
As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $30 million in the first quarter of 2011.
As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law onin 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 areunder prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $12.6$13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflectsThat charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.
Allegheny recorded as deferred income tax assets the effect of net operating losses and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. The tax effected net operating loss carryforwards consisted of $152 million of state net operating loss carryforwards that expire from 2019 through 2029 and $53 million of federal net operating loss carryforwards that expire from 2023 to 2029. Federal Alternative Minimum Tax credits of $25 million have an indefinite carryforward period.
Allegheny is currently under audit by the IRS for tax years 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. AllTax returns for all state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items were under appeal. In the fourth quarter of 2009, these items were settled at appeals and sent to Joint Committee on Taxation for final review. The federal audits for years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal.2006-2009. The IRS began auditing the year 2008 in February 2008 and the audit is expected to close before December 2010.was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and th ethe 2010 tax year audit began in February 2010. Neither audit is expected to close before December 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.
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8.9. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) 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 March 31, 2010,2011, outstanding guarantees and other assurances aggregated approximately $4.0$3.8 billion, consisting primarily of parental guarantees ($1.00.8 billion), subsidiaries’ guarantees ($2.6 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'counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy'sFirstEnergy’s guarantee enables the counterparty'scounterparty’s legal claim to be satisfied by othe rother FirstEnergy assets. TheFirstEnergy views as remote the likelihood is remote that such parental guarantees of $0.3$0.2 billion (included in the $1.0$0.8 billion discussed above) as of March 31, 20102011 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 aan LOC or accelerated payments may be required of the subsidiary. 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 was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of March 31, 2010, FirstEnergy's2011, FirstEnergy’s maximum exposure under these collateral provisions was $428$557 million, consisting of $37 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $328$433 million due to a below investment grade credit rating that includes the $46(of which $184 million relatedis due to the credit rating downgrade by S&P.an acceleration of payment or funding obligation) and $124 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 $656$623 million, consisting of $38$494 million due to “material adverse event” contractual clauses, $63a below investment grade credit rating (of which $184 million is related to an acceleration of payment or funding obligation,obligation) and $555$129 million due to a below investment grade credit rating.“material adverse event” contractual clauses.
Most of FirstEnergy'sFirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77$138 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 entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolio as of March 31, 2010,2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $270 million.$158 million and $5 million, respectively. 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 $168 million.$52 million of collateral. Depending on the volume of forward contracts and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.
be posted.
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, pursuant toand FES guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed 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.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, 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 lenders under the term loan facility as collateral for the facility.
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(B) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'sFirstEnergy’s earnings and competitive position to the extent that itFirstEnergy 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.
CAA Compliance
FirstEnergy accrues environmental 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. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations.regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. penalties.
The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis, Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired pla ntsplants 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 repoweringrepowering. OE and provides forPenn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.
In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional 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. In addition to seeking damages, twoTwo of the threethese 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 representa tives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008.representatives. FGCO believes thosethe claims are without merit and intends to defend itself against the allegations made in thosethese three complaints.
The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009, which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.
In December 2007, the statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 alleging NSR violations at the Portland Generation Station against Reliant (theGenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jerseythese suits allege that "modifications"“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting underin violation of the CAA'sCAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. Met-Ed filed a Motion to DismissIn September 2009, the claims in New Jersey’s Amende d Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed'sMet-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 on statutepenalties. The parties dispute the scope of limitations grounds in orderMet-Ed’s indemnity obligation to allowand from Sithe Energy, and Met-Ed is unable to predict the states to prove either that the applicationoutcome of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.
this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 2009, NOV1986 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. (Mission) alleging that "modifications"“modifications” at the Homer City Power Station occurred sincefrom 1988 to the present without preconstruction NSR or permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical to those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, 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'sCAA. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec 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 program.and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’s air emissions as well as 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, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) 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 is disputed.under dispute and Penelec is unable to predict the outcome of this matter.
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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. In September 2009, FGCO received an informationa request pursuant to Section 114(a) of the CAA requestingfor certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shorefor these same generating plants and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generati nggenerating plant may constitute a major modification under the NSR provision of the CAA. On December 23,Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA.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. A June 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.
In August 2008, FirstEnergy2000, AE received a requestletter from the EPA forrequesting that it provide information pursuantand documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114(a)114 of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complyingcompliance with the NSR provisionsCAA and related requirements, including potential application of the CAA. FirstEnergy intendsNSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to fully comply with the EPA’s informationthis and a subsequent request but at this time, is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired facilities: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NOX, SO2 and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.
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In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states.The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. CAIR was challenged inIn 2008, the U.S. Court of Appeals for the District of Columbia and on July 11, 2008, the CourtCircuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. 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 July 11, 2008Court’s opinion. On July 10, 2009, the U.S.The Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“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"“8-hour” ozone NAAQS. FGCO'sIn July 2010, the EPA proposed the Clean Air Transport Rule (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 with these regulations may be substantialsubstantial. Management is currently assessing the impact of these environmental proposals and will depend, in part,other factors on FGCO’s facilities, particularly on the action taken by the EPA in responseoperation of its smaller, non-supercritical units. For example, as disclosed herein, management decided to the Court’s ruling.idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions 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. Several states and environmental groups appealed the CAMR to the U.S. Court of Appeals for the District of Columbia. On February 8, 2008, the Court 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. The EPA petitioned for rehearing by the entire Court, which denied the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On April 15, 2010, the EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposedreleased its MACT regulations requirin g emissions reductions ofproposal to establish emission standards for mercury, hydrochloric acid and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedentvarious metals for MACT standards applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The U.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the U.S. Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. 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.
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, in June 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, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI 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 required FirstEnergy to measure GHG emissions commencing in 2010 and will require it 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 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. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO2 pollutants.
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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 whichthat recognized the scientific view that the increase in global temperature should be below two degrees Celsius, includedCelsius; includes 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 2020,2020; and establishedestablishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that 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. 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. 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.
On April 2, 2007, the U.S. Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. 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. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NSR and Title V oper ating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. 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 GHG increase the threat of climate change. In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the CAA will not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest.
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. On February 6, 2010,However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit granted defendants’ petition for rehearing en banc and on April 30, 2010,reinstated the Fifth Circuit cancelled the en banc hearing. On March 5, 2010, the Second Circuit denied defendants’ petition for rehearing and rehearing en banc.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 contribu tecontribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19, 2011, and a decision is expected by July 2011. While FirstEnergy is not a party to eitherthis litigation, should the courts of appeals decisions be affirmed or not subjected to further review, 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 of its 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'sFirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy'sFirstEnergy’s operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, theThe 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 large 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'sfacility’s cooling water system). On January 26, 2007,The EPA has taken the U.S. Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, notingposition that until further rulemaki ngrulemaking 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. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit Court’sCircuit’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. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of the Supreme Courtour existing generating facilities to assist permitting authorities to determine whether and the Courtwhat site-specific controls, if any, would be required to reduce entrainment of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard.aquatic life. FirstEnergy is studying various control options and their costs and effectiveness.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. In November 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 th ethe states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
TheIn April 2011, the U.S. Attorney'sAttorney’s Office in Cleveland, Ohio has advised FGCO that it is no longer 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. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.
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Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA has not acted on PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a TMDL limit for the river, a process that will take about five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.
In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.
Regulation of Waste Disposal
AsFederal 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, federal and state hazardous waste regulations have been promulgated.1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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 regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals.
In December 2009, the EPA provided to FGCO the findings of its review of the Bruce Mansfield Plant’s coal combustion residuals managem ent practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. OnIn May 4, 2010, the EPA issued a proposed rule that provides 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'sFirstEnergy’s future cost of compliance with any coal combustion residuals regulations whichthat 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.
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The UtilitiesUtility Registrants 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 March 31, 2010,2011, based on estimates of the total costs of cleanup, the Utilities'Utility Registrants proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $101$104 million (JCP&a mp;L - $74&L — $69 million, TE -— $1 million, CEI -— $1 million, FGCO -— $1 million and FirstEnergy - $24— $32 million) have been accrued through March 31, 2010.2011. Included in the total are accrued liabilities of approximately $67$64 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(C) 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.&L. 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'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. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1)On July 29, 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficie nt time to establish a damage model or individual proof of damages. On March 31, 2009,upheld the trial court again granted JCP&L’s motion to decertifycourt’s decision decertifying the class. On April 20, 2009, the Plaintiffs have filed, and JCP&L has opposed, a motion for leave to take an interlocutory appeal to the trial court's decision to decertifyNew Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class which was granted by the Appellate Division on June 15, 2009. Plaintiffs filedaction attempt, and leaves only nine (9) plaintiffs to pursue their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filedrespective individual claims. The remaining individual plaintiffs have not taken any affirmative steps to pursue their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.individual claims.
Litigation Relating to the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 14), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The plaintiffs allege that the merger consideration is unfair, that other terms in the merger agreement including the termination fee and the non-solicitation provision s are unfair, that certain individual defendants are financially interested in the merger, and that Allegheny Energy has failed to disclose material information about the merger to its shareholders. Among other remedies, the plaintiffs seek to enjoin the merger and they have demanded jury trials. The Allegheny Energy defendants moved to consolidate the Maryland lawsuits and filed motions to dismiss and answers to each of the Maryland complaints. The court consolidated the Maryland lawsuits and an amended complaint has been filed. The Allegheny Energy defendants, FirstEnergy, and Merger Sub filed motions to dismiss the amended complaint on April 21, 2010. The Maryland court has set a hearing for argument on the motions to dismiss for June 3, 2010. By order dated April 26, 2010, the Maryland court certified a plaintiff class that consists of all holders of Allegheny Energy shares at any time from February 11, 2010 to the consummation of the proposed merger. The Pennsylvania state court has consolidat ed the lawsuits filed in that court. The Allegheny Energy defendants and FirstEnergy have moved to stay the Pennsylvania lawsuits and the plaintiff has moved for leave to take expedited discovery. The Pennsylvania state court will hear argument on both motions on May 27, 2010. By stipulation dated April 14, 2010, no response is due to the complaint filed in the U.S. District Court for the Western District of Pennsylvania until June 10, 2010. While FirstEnergy and Allegheny Energy believe the lawsuits are without merit and intend to defend vigorously against the claims, the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy and Allegheny Energy. In accordance with its bylaws, Allegheny Energy will advance expenses to and, as necessary, indemnify all of its directors in connection with the foregoing proceedings. All applicable insur ance policies may not provide sufficient coverage for the claims under these lawsuits, and rights of indemnification with respect to these lawsuits will continue whether or not the merger is completed. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Nuclear Plant Matters
Davis Besse Control Rod Drive Mechanism Nozzles
During a planned refueling outage at Davis-Besse that began on February 28, 2010, FENOC initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 18, 2010, the NRC sent a special inspection team to Davis-Besse.
FENOC has begun a comprehensive investigation to determine the underlying cause for the cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July 2010.
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 such time that 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. What actions, if any, the NRC takes in response to this request have yet to be determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of March 31, 2010,2011, FirstEnergy had approximately $1.9$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy providedprovides an additional $80$15 million parental guarantee associated with the funding of decommissioning costs for these unitsunits. As required by the NRC, FirstEnergy annually recalculates and indicated that it plannedadjusts 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 contributefund the trusts may increase. Disruptions in the capital markets and their 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 with the decommissioning of FirstEnergy’s nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional $80 milliontwenty years, until 2037. By an order dated April 26, 2011, the NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions regarding (1) a combination of renewable alternatives to the renewal of Davis-Besse’s operating license, and (2) the cost of mitigating a severe accident at Davis-Besse. FENOC is currently evaluating these trusts by 2010. Bydevelopments and considering an appropriate response. On April 14, 2011, a letter dated March 8, 2010, primarilygroup of environmental organizations petitioned the NRC Commissioners to suspend all pending nuclear license renewal proceedings, including the Davis-Besse proceeding, to ensure that any safety and environmental implications of the Fukushima Daiichi Nuclear Power Station event in Japan are considered.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the Beaver V alley Power Station operating license renewal, FENOC requestedDOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the NRC reducelitigation of these claims. FirstEnergy parental guaranteefiled damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to $15 millionreview and notified the staff that it no longer planned to make the additional contributions into the trusts. FirstEnergy is awaiting the NRC’s decision on the proposed reduction of the parental guarantee.audit by DOE.
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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.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. OnIn February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The parties participated in the federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009.
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. OnIn 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 ruled on that motionrendered an opinion.
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to dismiss.FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The named-defendant companies will continue to defend these claims including challenging any class certification.
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'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, results of operations and cash flows.
9.10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
In 2005, Congress amended the FPA to provide for federally-enforceable mandatory reliability standards. TheFederally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI.ATSI and TrAIL Company. 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 responsibilitiesthese 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.
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, thetime; 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.
In April 2007, ReliabilityFirst performed 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, ReliabilityFirst performed 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. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.
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 withresulting in customers in the affected area losing power. Power was restoredpower for up to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. 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. The initial phase of the investigation requiredNERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviewsis complying with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009.these requests. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.with respect to this matter.
On June 5, 2009,August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta potentialvegetation 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. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict the final outcome of this investigation.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain violation investigations with regard to matters of NERC Standard PRC-005 resultingcompliance by Allegheny.
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(B) MARYLAND
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from its inabilitycapped generation rates to validate maintenance recordsrates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for 20 protection system relays (outall customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
By statute enacted in 2007, the obligation of approximately 20,000 reportable relays)Maryland utilities to provide SOS to residential and small commercial customers, in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered duringexchange for recovery of their costs plus a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance recordsreasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the relays. ReliabilityFirstMDPSC to report to the legislature on the status of SOS. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an Initial Noticeorder soliciting comments on a model request for proposal for solicitation of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9,long-term energy commitments by Maryland electric utilities. PE and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not ablenumerous other parties filed comments, and at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose forno further proceedings have been set by the MDPSC in this self-reported violation.matter.
(B) OHIO
On June 7,In September 2007, the Ohio Companies filedMDPSC issued an application for an increase in electric distribution rates withorder that required the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electricMaryland utilities to file an ESP,detailed plans for how they will meet the “EmPOWER Maryland” proposal that, in Maryland, electric consumption be reduced by 10% and permittedelectricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, the filing of an MRO. On July 31,Maryland legislature in 2008 adopted a statute codifying the Ohio CompaniesEmPOWER Maryland goals. In 2008, PE filed withits comprehensive plans for attempting to achieve those goals, asking the PUCOMDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a comprehensive ESPcustomer education program, and a separate MRO.pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed by the Ohio Companies was approved by the PUCO on December 19, 2008. The Ohio Companies thereafter withdrew and terminated the ESP and continued their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from Januar y 5, 2009 through March 31, 2009. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCOMDPSC ultimately approved the Ohio Companies’ request for a new fuel rider, which recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.
On February 19,programs in August 2009 the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signedafter certain modifications had been made as required by the Ohio Companies,MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the PUCO,MDPSC and manyother stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011.
In March 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. PE and several other utilities filed requests for reconsideration of various parts of the intervening parties. Specifically,order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the Amended ESP provided that generation would besummer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by FES atstatute, to three days on each occurrence.
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On March 24, 2011, the average wholesale rateMDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, the Maryland legislature is considering a bill addressing the same topics. The final bill passed on April 11, 2011, requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the MDPSC is directed to consider cost-effectiveness, and may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the CBP described aboveproposed rules.
In December 2009, PE filed an application with the MDPSC for Aprilauthorization to construct the Maryland portions of the PATH Project to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
(C) 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 NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011.
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero 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). Both matters are currently pending before the NJBPU.
(D) OHIO
The Ohio Companies operate under an ESP, which expires on May 2009 to31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to w rite-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider (Rider DSI) at an overall average rate of $.002$0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressedOhio Companies currently purchase generation at the average wholesale rate of a number of other issues, including but not limited to, rate design for various customer classes, and resolutionCBP conducted in May 2009. FES is one of the prudence reviewsuppliers 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 the collection of deferred costs that were approved in prior proceedings. On February 26,TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million).
In March 2010, the Ohio Companies filed an application for a Supplemental Stipulation,new ESP, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modifiedPUCO approved in August 2010, with certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding con tained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions.modifications. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions tooknew ESP will go into effect on June 1, 2009.
SB2212011 and conclude on May 31, 2014. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed on the October 2009 MRO filing (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also requires electricapplies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution utilitiesrates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to implementrecover 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 recover from retail customers certain costs related to the companies’ integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 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, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency programs. and alternative energy requirements. Many of the existing riders approved in the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent ofto 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 .75%0.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than t hree years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot.
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In its March 10, 2010, Entry the PUCO also found that the Ohio Companies peak demand reduction programs complied with PUCO rules.
The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. 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 PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmark s were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.
In October 2009, The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. Therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO issued additional Entries modifying certain of its previous rulesindicated, when approving the 2009 benchmark request, that set outit would modify the manner in which electric utilities, includingCompanies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies will be requiredwere not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring these them into compliance with their yet-to-be-defined modified benchmarks. Failure to comply with the benchmarks containedor to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in SB221the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the employmentoriginal CFL program that the Ohio Companies had previously suspended at the request of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements.the PUCO. Applications for rehearingRehearing were filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further considerationApril 22, 2011, regarding portions of the matters raised in those applications. ThePUCO’s decision, including the method for calculating savings and certain changes made by the PUCO has not yet issued a substantive Entry on Rehearing. The rules implementing the requirements of SB221 went into effect on December 10, 2009.
to specific programs.
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 serveserved 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 will bewere used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. OnIn March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure.market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’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. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark which application is still pending.
On October 20,by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies filedinitiated an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBPadditional RFP to secure generation supply for customers who do not shop with an alternative supplierRECs and would be similar, in all material respects,solar RECs needed to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PU CO has 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Althoughmeet the Ohio Companies requested a PUCO determination by January 18,Companies’ alternative energy requirements as set forth in SB221 for 2010 on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.
2011 and executed related contracts in August 2010. On March 23, 2010,April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. The PUCO has not yet acted on that application.
In February 2010, OE and CEI filed an application with the PUCO to establish a new ESP, which if approved bycredit for all-electric customers. In March 2010, the PUCO would go into effectordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on June 1, 2011December 31, 2008 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed byauthorized the Ohio Companies to defer incurred costs equivalent to the Staff ofdifference 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 in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and anauthorized deferral for the associated additional fourteenamounts. 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 signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation includeseek a CBP similarlong term solution to the one usedissue. Tariffs implementing this newly expanded credit went into effect in May 20092010 and the one proposedproceeding remains open. The hearing on the matter was held in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided byFebruary 2011. The matter has now been briefed and the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments inawait the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.PUCO’s decision.
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(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations.
On February 20, 2009, 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 via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD ) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.
On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which deniesthat denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directsdirected Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructsinstructed 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. OnIn 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 loss costs. By Order entered March 25, 2010, thelosses. The PPUC granted the requested stay until December 31, 2010. OnPursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and for the use of these funds to mitigate future generation rate increases which the PPUC approved. In 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. The argument before the Commonwealth Court, en banc, was held in December 2010. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7$252.7 million ($158.5188.0 million for Met-Ed and $41.2$64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2,
In May 2008, May 2009 and May 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011
On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the periodannual periods between June 1, 2009 through May2008 to 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, as requiredabove. The PPUC’s approval in connection withMay 2010 authorized an increase to the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPU C’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recoveredprovide for full recovery by December 31, 2010. Under this proposal, monthly bills
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. In August 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 in November 2009. Generation procurement began in January 2010.
In February 2010, Penn filed a Petition for Met-Ed’s customers would increase approximately 9.4%Approval of its Default Service Plan for the period June 20091, 2011 through May 2010.31, 2013. In July 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.
Pennsylvania adopted Act 129 became effective in 2008 and addressesto address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C PlansAct 129 also required utilities to file with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order onin February 26, 2010 approvinggiving final approval to all aspects of the final plansEE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010.
Act 129 also required utilities to fileWP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by August 14,Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the PPUCCommonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter technology procurementimplementation in the EE&C Plan, and installationthat inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan to provide fordoes not meet the installationTotal Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September, 2010, WP filed an amended EE&C Plan that is less reliant on smart meter technology within 15 years. On August 14, 2009, deployment, which the PPUC approved in January 2011.
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Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. ConsistentSMIP with the PPUC’s rules, thisPPUC in August 2009. This plan proposesproposed 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 atof approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter PlanSMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminatingdenying the provisionrecovery of interest inthrough the 1307(e) reconciliation;automatic adjustment clause; providing for the recovery of reasonable and prudent costs minusnet of resulting savings from installation and use of smart meters; and reflectingrequiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. OnIn 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 Smart Meter Implementation Plan (SMIP)SMIP for the Pennsylvania Companies. An orderMet-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with Chairman Cawley’s Motionthe Chairman’s Motion. 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, which the PPUC granted in part 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.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer Advocate filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is anticipated t o be enteredconsidered and that the Joint Petition for Settlement has adequate support in the near future,record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in which eventOctober 2010, adds the Pennsylvania Companies will move forwardPPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the Smart Meter Technology Procurement and Installation Plan.
Legislation addressing rate mitigation andOSBA was also filed on March 9, 2011. The proposed settlement remains subject to review by the expiration of rate caps was introduced inALJ, who will prepare an Initial Decision for consideration by the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed t ariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.
PPUC.By Tentative Order entered in September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “thethe 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 over-collectioncosts for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliancevarious parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s rep ly comments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.
In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. The PPUC has not yet initiated that investigation.
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(F) VIRGINIA
In September 2010, PATH-VA filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. On February 8, 2010, Penn28, 2011, PATH-VA filed a motion to withdraw the application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
(G) WEST VIRGINIA
In August 2009, MP and PE filed with the PPUCWVPSC a generation procurement plan coveringrequest to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.
(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 March 31, 2010, the accumulated deferred cost balance totaled approximately $55 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and al so submitted commentsrequirement included in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. 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. 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 EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, 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 BPU 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.
In support of former New Jersey Governor Corzine's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations.original filing. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformersin December 2009, subsidiaries of MP and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relatingPE completed a securitization transaction to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of thefinance certain costs associated with the proposal.installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
Ona deferral of February 11, 2010 S&P downgradedstorm restoration expenses in West Virginia over a maximum five-year period;
an additional $20 million annualized base rate increase effective in January 2011;
a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the senior unsecured debtJoint Petition and Agreement of FirstEnergy Corp.Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to BB+. Asretail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a result,predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative & renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville, the requirementsowner of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effectone of the downgrade and which providedcontracted resources, has filed an assessment of present and future liquidity necessaryopposition to assure JCP&L’s continued payment to BGS suppliers. The NJBPU subsequently held a public hearing to review the plan and available options. On March 17, 2010, the NJBPU determined that JCP&L demonstrated that it has ample resources available to continue uninterrupted payments to BGS suppliers and that there are no concerns with JCP&L's liquidity and therefore no further action is required.Petition.
(E)(H) FERC MATTERS
Rates for Transmission Service betweenBetween MISO and PJM
OnIn 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 the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. TheIn 2005, the FERC issued orders in 2005 settingset the SECA for hearing. The presiding judgeALJ issued an initial decision onin August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision is subj ectwas subject to review and approval by the FERC. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008,In May 2010, FERC issued an order approving uncontesteddenying 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 but did not rule onwith AEP, Dayton and the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with otherExelon 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 case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision.SECA period. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.
PJM Transmission Rate
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previouslyAEP, Dayton and Exelon, settlements were approved by the FERC. JCP&L, Met-EdFERC in November 2010, and Penelec were partiesthe relevant payments made. The Utilities have refund obligations that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy are not expected to that proceeding and joinedbe material. Rehearings remain pending in two of the filings. this proceeding.
PJM Transmission Rate
In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held on the content of the compliance filings and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the 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, the 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.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” basis. The FERC found that PJM’s current beneficiary-paysapproach to allocating the cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and rea sonable cost allocation methodology for inclusion in PJM’s tariff.
high voltage transmission facilities.
The FERC’s April 19, 2007Opinion 494 order and a related order denying a request for rehearing werewas appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin 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 postage-stampload ratio share basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies was denied by the Seventh Circuit on October 20, 2009.
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 within 45 days, and then reply comments 30 days later.on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. InterestedPJM’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 the costs. Numerous parties may filefiled responsive comments or studies byon May 28, 2010. Reply2010 and reply comments are due byon 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. This matter is awaiting action by the FERC.
RTO Consolidation
Realignment
On August 17, 2009, FirstEnergyFebruary 1, 2011, ATSI in conjunction with PJM filed an applicationits proposal with the FERC requesting to consolidatefor moving its transmission assets and operationsrate into PJM. Currently, FirstEnergy’s transmission assets and operations are divided betweenPJM’s tariffs. FirstEnergy expects ATSI to enter PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to coincide with deliverystart charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of power undercollecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the next competitive generation procurement processMISO submitted numerous filings for the Ohio Companies. To ensure a definitive ruling atpurpose of effecting movement of the same timeATSI zone to PJM on June 1, 2011. These filings include clean-up of the FERC rules on its requestMISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to integrate ATSIreflect the move into PJM, on Octoberand submission of changes to PJM’s tariffs to support the move into PJM.
FERC proceedings are pending in which ATSI’s transmission rate, the exit fee payable to MISO, transmission cost allocations and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the MISO are under review. The outcome of these proceedings cannot be predicted.
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MISO Multi-Value Project Rule Proposal
In July 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, 2009,2010, 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 $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
In September 2010, FirstEnergy filed a related complaintprotest 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 FERCestablished rule that cost allocation is to be based on the issuecost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of exemptingprogress to date in the ATSI footprint from the legacy RTEP costs.
On September 4, 2009, the PUCO opened a caseintegration into PJM, it would be unjust and unreasonable to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integrationallocate any MVP costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
OnIn December 17, 2009,2010, FERC issued an order approving subjectthe MVP proposal without significant change. FERC’s order was not clear, however, as to certain future compliance filings,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 move to PJM. FirstEnergy’s requestexit but ruled that the question of the amount of costs that are to be exempted from legacy RTEP costs was rejected and its complaint dismissed.
On December 17, 2009,allocated to ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’sor to load to moving into PJM on the schedule described in the applicationATSI zone were beyond the scope of FERC’s order and approvedwould be addressed in the FERC Order (June 1, 2011).
future proceedings.
On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010,18, 2011, FirstEnergy filed for rehearing of FERC’s decision to imposeorder. In its rehearing request, FirstEnergy argued that because the legacy RTEPMVP rate is usage-based, costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.
On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March 25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the FPA. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January 2009. The request for settlement hearings was granted. Settlement hadapplied to ATSI, which is a stand-alone transmission company that does not been reached by January 9, 2009use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and accordingly, F irstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time.
PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008 apply.Calculation Error
OnIn March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.
MISO Complaints Versus PJM
On March 9, 2010, MISO filed two complaints at FERC against PJM with FERC under Sections 206, 306,relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and 309 of the FPA alleging violations of the MISO/MISO since April 2005. MISO claimed that this error resulted in PJM Joint Operating Agreement (JOA). In the first complaint,underpaying MISO alleged that by failing to account for the market flows from 34 PJM generatorsapproximately $130 million over the time period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint,in question. Additionally, MISO alleged that PJM has refuseddid not properly trigger market-to-market settlements between PJM and MISO during times when it was required to comply with provisionsdo so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of the JOA requiring market-to-market dispatch since 2009,any refunds ordered in this case. PJM, Allegheny and is improperly demanding repayment of redispatch payments previously madeother PJM market participants filed responses to MISO.
PJM filed its answers to theMISO complaints on April 12, 2010, opposing the relief sought by MISO. In addition, on April 12, 2010,and PJM filed a related complaint withat FERC pursuant to Section 206, 306, and 309 allegingagainst MISO claiming that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlementsimproperly called for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantiallyseveral times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues asin the second MISO complaint, in which MISO argues thatdispute. The Offer of Settlement calls for the usewithdrawal of proxy flowgates is permittedall pending complaints with no payments being made by agreementany parties. Initial comments on the Offer of the RTOsSettlement were filed at FERC on January 24, 2011. FirstEnergy and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
FirstEnergy has intervened in all three proceedings, and timelyAllegheny Energy filed comments supporting MISOthe proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. In April 2010, the California parties filed exceptions to the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.
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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with the FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before the FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.
Transmission Expansion
TrAIL Project.TrAIL is a 500kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.
PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its first complaint,2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the potential need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC and the WVPSC has granted the motion to withdraw. The VSCC has not ruled on the motion to withdraw.
PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to improper accountingthe formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of market flows resultinga return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in underpayments from 2005-2009.settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. FirstEnergy is unable tocannot predict the outcome of this matter.proceeding or whether it will have a material impact on its operating results.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.
10.11. STOCK-BASED COMPENSATION PLANS
FirstEnergy has four types of stock-based compensation programs including LTIP, EDCP, ESOP and DCPD, as described below.
In addition, Allegheny’s stock-based awards were converted into First Energy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.
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(A) LTIP
FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.
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 be settled 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. There were 6.3 million shares available for future awards as of March 31, 2011.
Restricted Stock and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:
| | | | |
| | Three Months | |
| | Ended | |
| | March 31, 2011 | |
|
| Restricted stock and stock units outstanding as of January 1, 2011 | | | 1,878,022 | |
| Granted | | | 223,161 | |
| Converted Allegheny restricted stock | | | 645,197 | |
| Exercised | | | (422,031 | ) |
| Forfeited | | | (37,182 | ) |
| | | |
| Restricted stock and stock units outstanding as of March 31, 2011 | | | 2,287,167 | |
| | | |
The 223,161 shares of restricted common stock granted during the three months ended March 31, 2011 had a grant-date fair value of $8.2 million and a weighted-average vesting period of 1.86 years.
Restricted stock units include awards that will be settled in a specific number of shares of stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of stock based on FirstEnergy’s performance compared to annual target performance metrics.
Compensation expense recognized for the three months ended March 31, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $16 million and $6 million, respectively.
Stock Options
Stock option activity for the three months ended March 31, 2011 was as follows:
| | | | | | | | | |
| | | | | | | Weighted | |
| | | | | | | Average | |
| | | Number of | | | Exercise | |
| Stock Option Activities | | Shares | | | Price | |
| |
| Stock options outstanding as of January 1, 2011 (all exercisable) | | | 2,889,066 | | | $ | 35.18 | |
| Options granted | | | 662,122 | | | | 37.75 | |
| Converted Allegheny options | | | 1,805,811 | | | | 41.75 | |
| Options exercised | | | (182,422 | ) | | | 29.56 | |
| Options forfeited/expired | | | (6,670 | ) | | | 69.36 | |
| | | | | | | |
| Stock options outstanding as of March 31, 2011 | | | 5,167,907 | | | $ | 37.96 | |
| | | | | | | |
| (4,505,785 options exercisable) | | | | | | | | |
Compensation expense recognized for stock options during the three months ended March 31, 2011 was $0.1 million. No expense was recognized during the three months ending March 31, 2010. Options granted during the three months ended March 31, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.
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Options outstanding by exercise price as of March 31, 2011 were as follows:
| | | | | | | | | | | | | |
| | | | | | | Weighted | | | Remaining | |
| | | Shares Under | | | Average | | | Contractual | |
| Exercise Prices | | Options | | | Exercise Price | | | Life in Years | |
| |
| $20.02 – $30.74 | | | 1,305,563 | | | $ | 26.72 | | | | 2.01 | |
| $30.89 – $40.93 | | | 3,378,866 | | | | 37.22 | | | | 4.79 | |
| $42.72 – $51.82 | | | 37,233 | | | | 44.40 | | | | 0.24 | |
| $53.06 – $62.97 | | | 54,559 | | | | 56.15 | | | | 3.27 | |
| $64.52 – $71.82 | | | 54,778 | | | | 68.52 | | | | 1.09 | |
| $73.39 – $80.47 | | | 327,570 | | | | 80.19 | | | | 6.01 | |
| $81.19 – $89.59 | | | 9,338 | | | | 83.51 | | | | 1.92 | |
| | | | | | | | | | |
| Total | | | 5,167,907 | | | $ | 37.96 | | | | 4.07 | |
| | | | | | | | | | |
Performance Shares
Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the three months ended March 31, 2011 and 2010, net of amounts capitalized, totaled $1 million and $(3) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the three months ended March 31, 2011 and 2010.
(B) ESOP
During 2011 shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the three months ended March 31, 2011 and 2010, net of amounts capitalized and dividends on common stock were $7 million and $5 million, respectively.
(C) EDCP
Compensation expense (income) recognized on EDCP stock units, for the three months ended March 31, 2011 and 2010, net of amounts capitalized, was not material.
(D) DCPD
DCPD expenses recognized for the three months ended March 31, 2011 and 2010 were approximately $1 million and $1 million. The net liability recognized for DCPD of approximately $5 million as of March 31, 2011 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, 1,076,779 stock units were available for future awards as of March 31, 2011.
12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
During the three months ended March 31, 2011, there were no new accounting standards or interpretations issued, but not effective that would materially affect FirstEnergy’s financial statements.
In 2010,13. SEGMENT INFORMATION
With the FASB amended the Derivatives and Hedging Topiccompletion of the FASB Accounting Standards CodificationAllegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to clarifyits operating segments to be consistent with the scope exception for embedded credit derivative features relatedmanner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting utilized by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.
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Prior to the transferchange in composition of credit riskbusiness segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the following:
Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the form“Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of subordinationATSI, and the operations of one financial instrument to another.TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The amendment addresses how to determine which embedded credit derivative features, including those in collateralized debt obligationstransmission assets and synthetic collateralized debt obligations, are considered to be embedded derivativesoperations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that should not be analyzed underwas acquired as part of the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective formerger with Allegheny, was placed into the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard to have a material effect on its financial statements.Competitive Energy Services segment.
11. SEGMENT INFORMATION
Financial information for each of FirstEnergy’s reportable segments is presented in the following table.table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments. With the completion of transition to a fully competitive generation market in Ohio in the fourth quarter of 2009, the former Ohio Transitional Generation Services segment was combined with the Energy Delivery Services segment, consistent with how management views the business. Disclosures for FirstEnergy’s operating segments for 2009 have been reclassified to conform to the current presentation.
The energy delivery servicesRegulated Distribution segment transmits and distributes electricity through FirstEnergy’s eightten utility operating companies, serving 4.5approximately 6 million customers within 36,10067,000 square miles of Ohio, Pennsylvania, West Virginia, Virginia, Maryland, New Jersey and New JerseyYork, and purchases power for its PLRPOLR and default service requirements in Ohio, Pennsylvania and New Jersey. ItsThis segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.
The Regulated Distribution segment’s 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(POLR or default service) in its Ohio, Pennsylvania andMaryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.
The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from the formula rate recovery of costs and a return on debt and equity for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the deliver ydelivery of the respective generation loads, andloads. On June 1, 2011, the deferral and amortizationATSI transmission assets currently dedicated to MISO are scheduled to be integrated into the PJM market. This integration brings all of certain fuel costs.
FirstEnergy’s assets into one RTO.
The competitive energy servicesCompetitive Energy Services segment, through FES, 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 PLRPOLR and default service requirements of FirstEnergy'sFirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and Michigan. New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.
The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.
This business segment owns or leases and operates 19 generating facilities with a net demonstratedcontrols approximately 20,000 MWs of capacity of 13,710 MWs and also purchases electricity to meet sales obligations. The segment'ssegment’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 MI SOMISO to deliver energy to the segment’s customers.
69
The otherOther segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
Segment Financial Information
| Segment Financial Information | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | Energy | | | Competitive | | | | | | | | | | | | Competitive | | Regulated | | | | | | | |
| | | | Delivery | | | Energy | | | | | | Reconciling | | | | | | Regulated | | Energy | | Independent | | Other/ | | Reconciling | | | |
| Three Months Ended | Three Months Ended | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | | | Distribution | | Services | | Transmission | | Corporate | | Adjustments | | Consolidated | |
| | | | (In millions) | | | (In millions) | |
| March 31, 2010 | | | | | | | | | | | | | | | | |
March 31, 2011 | | |
| External revenues | External revenues | | $ | 2,543 | | | $ | 716 | | | $ | 4 | | | $ | (31 | ) | | $ | 3,232 | | | $ | 2,268 | | $ | 1,254 | | $ | 67 | | $ | (23 | ) | | $ | (22 | ) | | $ | 3,544 | |
| Internal revenues | Internal revenues | | | - | | | | 674 | | | | - | | | | (607 | ) | | | 67 | | | — | | 343 | | — | | — | | | (311 | ) | | 32 | |
| | Total revenues | | | 2,543 | | | | 1,390 | | | | 4 | | | | (638 | ) | | | 3,299 | | | | | | | | | | | | | | |
| Total revenues | | | 2,268 | | 1,597 | | 67 | | | (23 | ) | | | (333 | ) | | 3,576 | |
| Depreciation and amortization | Depreciation and amortization | | | 325 | | | | 66 | | | | 13 | | | | 1 | | | | 405 | | | 245 | | 88 | | 13 | | 6 | | — | | 352 | |
| Investment income (loss), net | Investment income (loss), net | | | 25 | | | | 1 | | | | - | | | | (10 | ) | | | 16 | | | 25 | | 6 | | — | | — | | | (10 | ) | | 21 | |
| Net interest charges | Net interest charges | | | 123 | | | | 33 | | | | (1 | ) | | | 17 | | | | 172 | | | 131 | | 68 | | 9 | | 19 | | | (14 | ) | | 213 | |
| Income taxes | Income taxes | | | 69 | | | | 47 | | | | 4 | | | | (9 | ) | | | 111 | | | 56 | | 3 | | 7 | | | (20 | ) | | 32 | | 78 | |
| Net income (loss) | Net income (loss) | | | 114 | | | | 76 | | | | (15 | ) | | | (26 | ) | | | 149 | | | 96 | | 5 | | 13 | | | (35 | ) | | | (34 | ) | | 45 | |
| Total assets | Total assets | | | 22,530 | | | | 10,948 | | | | 605 | | | | (5 | ) | | | 34,078 | | | 27,165 | | 17,308 | | 2,479 | | 914 | | — | | 47,866 | |
| Total goodwill | Total goodwill | | | 5,551 | | | | 24 | | | | - | | | | - | | | | 5,575 | | | 5,551 | | 976 | | — | | — | | — | | 6,527 | |
| Property additions | Property additions | | | 166 | | | | 323 | | | | 3 | | | | 16 | | | | 508 | | | 177 | | 214 | | 27 | | 31 | | — | | 449 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| March 31, 2009 | | | | | | | | | | | | | | | | | | | | | |
March 31, 2010 | | |
| External revenues | External revenues | | $ | 3,021 | | | $ | 335 | | | $ | 7 | | | $ | (29 | ) | | $ | 3,334 | | | $ | 2,484 | | $ | 719 | | $ | 57 | | $ | (22 | ) | | $ | (6 | ) | | $ | 3,232 | |
| Internal revenues | Internal revenues | | | - | | | | 893 | | | | - | | | | (893 | ) | | | - | | | — | | 674 | | — | | — | | | (607 | ) | | 67 | |
| | Total revenues | | | 3,021 | | | | 1,228 | | | | 7 | | | | (922 | ) | | | 3,334 | | | | | | | | | | | | | | |
| Total revenues | | | 2,484 | | 1,393 | | 57 | | | (22 | ) | | | (613 | ) | | 3,299 | |
| Depreciation and amortization | Depreciation and amortization | | | 427 | | | | 64 | | | | 1 | | | | 3 | | | | 495 | | | 313 | | 77 | | 12 | | 3 | | — | | 405 | |
| Investment income (loss), net | Investment income (loss), net | | | 30 | | | | (29 | ) | | | - | | | | (12 | ) | | | (11 | ) | | 26 | | 1 | | — | | 1 | | | (12 | ) | | 16 | |
| Net interest charges | Net interest charges | | | 109 | | | | 18 | | | | 1 | | | | 38 | | | | 166 | | | 124 | | 33 | | 5 | | 13 | | | (3 | ) | | 172 | |
| Income taxes | Income taxes | | | (12 | ) | | | 103 | | | | (17 | ) | | | (20 | ) | | | 54 | | | 62 | | 42 | | 7 | | | (12 | ) | | 12 | | 111 | |
| Net income | | | (18 | ) | | | 155 | | | | 17 | | | | (39 | ) | | | 115 | | |
| Net income (loss) | | | 103 | | 69 | | 12 | | | (19 | ) | | | (16 | ) | | 149 | |
| Total assets | Total assets | | | 23,005 | | | | 9,925 | | | | 632 | | | | (5 | ) | | | 33,557 | | | 21,535 | | 10,950 | | 995 | | 598 | | — | | 34,078 | |
| Total goodwill | Total goodwill | | | 5,550 | | | | 24 | | | | - | | | | - | | | | 5,574 | | | 5,551 | | 24 | | — | | — | | — | | 5,575 | |
| Property additions | Property additions | | | 165 | | | | 421 | | | | 49 | | | | 19 | | | | 654 | | | 152 | | 329 | | 14 | | 13 | | — | | 508 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| * | 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.
14. IMPAIRMENT OF LONG-LIVED ASSETS
12.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. Two events occurred during the first quarter of 2011 that indicated the carrying value of certain assets may not be recoverable as described in the sections below.
Fremont Energy Center
On March 11, 2011, FirstEnergy and American Municipal Power, Inc., (AMP) entered into an agreement for the sale of 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. The agreement provides, among other things, for a targeted closing date in July 2011. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On April 19, 2011, FGCO filed an section 203 application with the FERC for authorization to sell the Fremont Energy Center, including related capacity supply obligations, to AMP. Comments are due on the filing on or before May 10, 2011. FGCO requested FERC action by June 17, 2011.
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Peaking Facilities
During the three months ended March 31, 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $14 million to the operating income of its Competitive Energy Services segment during the quarter ended March 31, 2011.
15. ASSET RETIREMENT OBLIGATIONS
FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).
The ARO liabilities for FES and OE include the decommissioning of the Perry nuclear generating facilities. FES and OE use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.
During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively, as of March 31, 2011.
The revision to the estimated cash flows had no significant impact on accretion of the obligation during the first quarter of 2011 when compared to the first quarter of 2010.
16. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO'sFGCO’s obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FGCO, but the notes are secured by, among other things, each lessor trust'strust’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including FES'FES’ lease guaranty. This transaction is classified as an operating lease under GAAP for FES and FirstEnergy and as a financing for FGCO.
The condensed consolidating statements of income for the three-monthsthree month periods ended March 31, 20102011 and 2009,2010, consolidating balance sheets as of March 31, 20102011 and December 31, 20092010 and consolidating statements of cash flows for the three months ended March 31, 20102011 and 20092010 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'FES’ investment accounts and earnings as if operating lease treatment was achieved. 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 transac tion.transaction.
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FIRSTENERGY SOLUTIONS CORP. 55CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | | | | | | |
REVENUES | | $ | 1,366,899 | | | $ | 742,638 | | | $ | 467,967 | | | $ | (1,186,416 | ) | | $ | 1,391,088 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 1,203 | | | | 293,862 | | | | 48,044 | | | | — | | | | 343,109 | |
| Purchased power from affiliates | | | 1,184,606 | | | | 1,772 | | | | 68,743 | | | | (1,186,378 | ) | | | 68,743 | |
| Purchased power from non-affiliates | | | 296,733 | | | | 205 | | | | — | | | | — | | | | 296,938 | |
| Other operating expenses | | | 177,529 | | | | 118,245 | | | | 188,009 | | | | 12,152 | | | | 495,935 | |
| Provision for depreciation | | | 879 | | | | 31,539 | | | | 37,333 | | | | (1,299 | ) | | | 68,452 | |
| General taxes | | | 12,263 | | | | 9,453 | | | | 7,389 | | | | — | | | | 29,105 | |
| Impairment of long-lived assets | | | — | | | | 13,800 | | | | — | | | | — | | | | 13,800 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 1,673,213 | | | | 468,876 | | | | 349,518 | | | | (1,175,525 | ) | | | 1,316,082 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (306,314 | ) | | | 273,762 | | | | 118,449 | | | | (10,891 | ) | | | 75,006 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 676 | | | | 232 | | | | 4,953 | | | | — | | | | 5,861 | |
| Miscellaneous income, including net income from equity investees | | | 247,859 | | | | 584 | | | | — | | | | (229,202 | ) | | | 19,241 | |
| Interest expense — affiliates | | | (50 | ) | | | (451 | ) | | | (516 | ) | | | — | | | | (1,017 | ) |
| Interest expense — other | | | (24,133 | ) | | | (27,758 | ) | | | (16,836 | ) | | | 15,767 | | | | (52,960 | ) |
| Capitalized interest | | | 131 | | | | 4,826 | | | | 4,962 | | | | — | | | | 9,919 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 224,483 | | | | (22,567 | ) | | | (7,437 | ) | | | (213,435 | ) | | | (18,956 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | | (81,831 | ) | | | 251,195 | | | | 111,012 | | | | (224,326 | ) | | | 56,050 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (117,841 | ) | | | 93,129 | | | | 42,374 | | | | 2,454 | | | | 20,116 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | | 36,010 | | | | 158,066 | | | | 68,638 | | | | (226,780 | ) | | | 35,934 | |
| | | | | | | | | | | | | | | | | | | | | |
| Loss attributable to noncontrolling interest | | | — | | | | (76 | ) | | | — | | | | — | | | | (76 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 36,010 | | | $ | 158,142 | | | $ | 68,638 | | | $ | (226,780 | ) | | $ | 36,010 | |
| | | | | | | | | | | | | | | | |
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FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | | | | | | |
REVENUES | | $ | 1,367,025 | | | $ | 568,364 | | | $ | 426,320 | | | $ | (973,616 | ) | | $ | 1,388,093 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 5,097 | | | | 280,863 | | | | 42,261 | | | | — | | | | 328,221 | |
| Purchased power from affiliates | | | 968,537 | | | | 5,079 | | | | 60,953 | | | | (973,616 | ) | | | 60,953 | |
| Purchased power from non-affiliates | | | 450,216 | | | | — | | | | — | | | | — | | | | 450,216 | |
| Other operating expenses | | | 53,125 | | | | 99,776 | | | | 139,420 | | | | 12,189 | | | | 304,510 | |
| Provision for depreciation | | | 790 | | | | 26,527 | | | | 36,910 | | | | (1,309 | ) | | | 62,918 | |
| General taxes | | | 5,498 | | | | 14,600 | | | | 6,648 | | | | — | | | | 26,746 | |
| Impairment of long-lived assets | | | — | | | | 1,833 | | | | — | | | | — | | | | 1,833 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 1,483,263 | | | | 428,678 | | | | 286,192 | | | | (962,736 | ) | | | 1,235,397 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (116,238 | ) | | | 139,686 | | | | 140,128 | | | | (10,880 | ) | | | 152,696 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income (loss) | | | 1,897 | | | | 54 | | | | (1,234 | ) | | | — | | | | 717 | |
| Miscellaneous income (expense), including net income from equity investees | | | 166,373 | | | | 200 | | | | (101 | ) | | | (163,329 | ) | | | 3,143 | |
| Interest expense — affiliates | | | (58 | ) | | | (1,812 | ) | | | (435 | ) | | | — | | | | (2,305 | ) |
| Interest expense — other | | | (23,373 | ) | | | (26,506 | ) | | | (15,763 | ) | | | 15,998 | | | | (49,644 | ) |
| Capitalized interest | | | 100 | | | | 16,333 | | | | 3,257 | | | | — | | | | 19,690 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 144,939 | | | | (11,731 | ) | | | (14,276 | ) | | | (147,331 | ) | | | (28,399 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 28,701 | | | | 127,955 | | | | 125,852 | | | | (158,211 | ) | | | 124,297 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (51,225 | ) | | | 48,043 | | | | 45,013 | | | | 2,540 | | | | 44,371 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 79,926 | | | $ | 79,912 | | | $ | 80,839 | | | $ | (160,751 | ) | | $ | 79,926 | |
| | | | | | | | | | | | | | | | |
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| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,367,025 | | | $ | 568,364 | | | $ | 426,320 | | | $ | (973,616 | ) | | $ | 1,388,093 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 5,097 | | | | 280,863 | | | | 42,261 | | | | - | | | | 328,221 | |
| Purchased power from affiliates | | | 968,537 | | | | 5,079 | | | | 60,953 | | | | (973,616 | ) | | | 60,953 | |
| Purchased power from non-affiliates | | | 450,215 | | | | - | | | | - | | | | - | | | | 450,215 | |
| Other operating expenses | | | 53,126 | | | | 99,776 | | | | 139,420 | | | | 12,189 | | | | 304,511 | |
| Provision for depreciation | | | 790 | | | | 26,527 | | | | 36,910 | | | | (1,309 | ) | | | 62,918 | |
| General taxes | | | 5,498 | | | | 14,600 | | | | 6,648 | | | | - | | | | 26,746 | |
| Total expenses | | | 1,483,263 | | | | 426,845 | | | | 286,192 | | | | (962,736 | ) | | | 1,233,564 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | | (116,238 | ) | | | 141,519 | | | | 140,128 | | | | (10,880 | ) | | | 154,529 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 1,897 | | | | 54 | | | | (1,234 | ) | | | - | | | | 717 | |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | |
| net income from equity investees | | | 166,373 | | | | (1,633 | ) | | | (101 | ) | | | (163,329 | ) | | | 1,310 | |
| Interest expense to affiliates | | | (58 | ) | | | (1,812 | ) | | | (435 | ) | | | - | | | | (2,305 | ) |
| Interest expense - other | | | (23,373 | ) | | | (26,506 | ) | | | (15,763 | ) | | | 15,998 | | | | (49,644 | ) |
| Capitalized interest | | | 100 | | | | 16,333 | | | | 3,257 | | | | - | | | | 19,690 | |
| Total other income (expense) | | | 144,939 | | | | (13,564 | ) | | | (14,276 | ) | | | (147,331 | ) | | | (30,232 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 28,701 | | | | 127,955 | | | | 125,852 | | | | (158,211 | ) | | | 124,297 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | | (51,225 | ) | | | 48,043 | | | | 45,013 | | | | 2,540 | | | | 44,371 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 79,926 | | | $ | 79,912 | | | $ | 80,839 | | | $ | (160,751 | ) | | $ | 79,926 | |
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| As of March 31, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
ASSETS | | | | | | | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 6,831 | | | $ | 8 | | | $ | — | | | $ | 6,839 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 388,951 | | | | — | | | | — | | | | — | | | | 388,951 | |
| Associated companies | | | 621,241 | | | | 500,097 | | | | 269,750 | | | | (857,808 | ) | | | 533,280 | |
| Other | | | 27,966 | | | | 7,617 | | | | 51,128 | | | | — | | | | 86,711 | |
| Notes receivable from associated companies | | | 5,742 | | | | 389,312 | | | | 83,364 | | | | — | | | | 478,418 | |
| Materials and supplies, at average cost | | | 46,747 | | | | 251,190 | | | | 191,060 | | | | — | | | | 488,997 | |
| Derivatives | | | 328,156 | | | | — | | | | — | | | | — | | | | 328,156 | |
| Prepayments and other | | | 41,403 | | | | 9,093 | | | | 948 | | | | (506 | ) | | | 50,938 | |
| | | | | | | | | | | | | | | | |
| | | | 1,460,206 | | | | 1,164,140 | | | | 596,258 | | | | (858,314 | ) | | | 2,362,290 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 99,899 | | | | 6,102,623 | | | | 5,421,719 | | | | (384,676 | ) | | | 11,239,565 | |
| Less — Accumulated provision for depreciation | | | 17,918 | | | | 2,035,726 | | | | 2,230,588 | | | | (176,690 | ) | | | 4,107,542 | |
| | | | | | | | | | | | | | | | |
| | | | 81,981 | | | | 4,066,897 | | | | 3,191,131 | | | | (207,986 | ) | | | 7,132,023 | |
| Construction work in progress | | | 8,139 | | | | 147,546 | | | | 600,620 | | | | — | | | | 756,305 | |
| Property, plant and equipment held for sale, net | | | — | | | | 476,602 | | | | — | | | | — | | | | 476,602 | |
| | | | | | | | | | | | | | | | |
| | | | 90,120 | | | | 4,691,045 | | | | 3,791,751 | | | | (207,986 | ) | | | 8,364,930 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | — | | | | — | | | | 1,159,903 | | | | — | | | | 1,159,903 | |
| Investment in associated companies | | | 5,175,787 | | | | — | | | | — | | | | (5,175,787 | ) | | | — | |
| Other | | | 371 | | | | 9,171 | | | | 202 | | | | — | | | | 9,744 | |
| | | | | | | | | | | | | | | | |
| | | | 5,176,158 | | | | 9,171 | | | | 1,160,105 | | | | (5,175,787 | ) | | | 1,169,647 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income tax benefits | | | 32,544 | | | | 376,182 | | | | — | | | | (408,726 | ) | | | — | |
| Customer intangibles | | | 131,870 | | | | — | | | | — | | | | — | | | | 131,870 | |
| Goodwill | | | 24,248 | | | | — | | | | — | | | | — | | | | 24,248 | |
| Property taxes | | | — | | | | 16,463 | | | | 24,649 | | | | — | | | | 41,112 | |
| Unamortized sale and leaseback costs | | | — | | | | 23,288 | | | | — | | | | 67,515 | | | | 90,803 | |
| Derivatives | | | 211,223 | | | | — | | | | — | | | | — | | | | 211,223 | |
| Other | | | 26,661 | | | | 75,647 | | | | 8,157 | | | | (57,408 | ) | | | 53,057 | |
| | | | | | | | | | | | | | | | |
| | | | 426,546 | | | | 491,580 | | | | 32,806 | | | | (398,619 | ) | | | 552,313 | |
| | | | | | | | | | | | | | | | |
| | | $ | 7,153,030 | | | $ | 6,355,936 | | | $ | 5,580,920 | | | $ | (6,640,706 | ) | | $ | 12,449,180 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 785 | | | $ | 373,550 | | | $ | 632,106 | | | $ | (19,578 | ) | | $ | 986,863 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 321,133 | | | | 39,410 | | | | — | | | | — | | | | 360,543 | |
| Other | | | — | | | | 661 | | | | — | | | | — | | | | 661 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 769,133 | | | | 290,902 | | | | 208,889 | | | | (768,988 | ) | | | 499,936 | |
| Other | | | 92,874 | | | | 96,270 | | | | — | | | | — | | | | 189,144 | |
| Accrued taxes | | | 2,721 | | | | 98,597 | | | | 65,919 | | | | (100,744 | ) | | | 66,493 | |
| Derivatives | | | 380,744 | | | | — | | | | — | | | | — | | | | 380,744 | |
| Other | | | 31,698 | | | | 119,402 | | | | 26,282 | | | | 47,143 | | | | 224,525 | |
| | | | | | | | | | | | | | | | |
| | | | 1,599,088 | | | | 1,018,792 | | | | 933,196 | | | | (842,167 | ) | | | 2,708,909 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder’s equity | | | 3,824,540 | | | | 2,673,372 | | | | 2,487,105 | | | | (5,160,461 | ) | | | 3,824,556 | |
| Long-term debt and other long-term obligations | | | 1,488,455 | | | | 2,113,043 | | | | 793,250 | | | | (1,249,751 | ) | | | 3,144,997 | |
| | | | | | | | | | | | | | | | |
| | | | 5,312,995 | | | | 4,786,415 | | | | 3,280,355 | | | | (6,410,212 | ) | | | 6,969,553 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | — | | | | — | | | | — | | | | 950,726 | | | | 950,726 | |
| Accumulated deferred income taxes | | | — | | | | — | | | | 456,556 | | | | (339,053 | ) | | | 117,503 | |
| Accumulated deferred investment tax credits | | | — | | | | 32,511 | | | | 20,670 | | | | | | | | 53,181 | |
| Asset retirement obligations | | | — | | | | 27,114 | | | | 839,529 | | | | — | | | | 866,643 | |
| Retirement benefits | | | 48,818 | | | | 240,467 | | | | — | | | | — | | | | 289,285 | |
| Property taxes | | | — | | | | 16,463 | | | | 24,649 | | | | — | | | | 41,112 | |
| Lease market valuation liability | | | — | | | | 205,366 | | | | — | | | | — | | | | 205,366 | |
| Derivatives | | | 168,409 | | | | — | | | | — | | | | — | | | | 168,409 | |
| Other | | | 23,720 | | | | 28,808 | | | | 25,965 | | | | — | | | | 78,493 | |
| | | | | | | | | | | | | | | | |
| | | | 240,947 | | | | 550,729 | | | | 1,367,369 | | | | 611,673 | | | | 2,770,718 | |
| | | | | | | | | | | | | | | | |
| | | $ | 7,153,030 | | | $ | 6,355,936 | | | $ | 5,580,920 | | | $ | (6,640,706 | ) | | $ | 12,449,180 | |
| | | | | | | | | | | | | | | | |
74
FIRSTENERGY SOLUTIONS CORP. 56CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| Other | | | — | | | | — | | | | — | | | | — | | | | — | |
| 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: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder’s 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 | |
| Derivatives | | | 81,393 | | | | — | | | | — | | | | — | | | | 81,393 | |
| Other | | | 25,798 | | | | 23,674 | | | | 17,242 | | | | — | | | | 66,714 | |
| | | | | | | | | | | | | | | | |
| | | | 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 | |
| | | | | | | | | | | | | | | | |
75
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (215,124 | ) | | $ | 267,047 | | | $ | 41,702 | | | $ | — | | | $ | 93,625 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | — | | | | 90,190 | | | | 60,000 | | | | — | | | | 150,190 | |
| Short-term borrowings, net | | | 321,134 | | | | 28,509 | | | | — | | | | — | | | | 349,643 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (130,208 | ) | | | (141,220 | ) | | | (60,000 | ) | | | — | | | | (331,428 | ) |
| Other | | | (430 | ) | | | (222 | ) | | | (365 | ) | | | — | | | | (1,017 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) financing activities | | | 190,496 | | | | (22,743 | ) | | | (365 | ) | | | — | | | | 167,388 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (2,858 | ) | | | (39,791 | ) | | | (116,357 | ) | | | — | | | | (159,006 | ) |
| Sales of investment securities held in trusts | | | — | | | | — | | | | 215,620 | | | | — | | | | 215,620 | |
| Purchases of investment securities held in trusts | | | — | | | | — | | | | (230,912 | ) | | | — | | | | (230,912 | ) |
| Loans from (to) associated companies, net | | | 28,589 | | | | (200,516 | ) | | | 90,280 | | | | — | | | | (81,647 | ) |
| Customer acquisition costs | | | (1,103 | ) | | | — | | | | — | | | | — | | | | (1,103 | ) |
| Other | | | — | | | | (6,439 | ) | | | 32 | | | | — | | | | (6,407 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) investing activities | | | 24,628 | | | | (246,746 | ) | | | (41,337 | ) | | | — | | | | (263,455 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | — | | | | (2,442 | ) | | | — | | | | — | | | | (2,442 | ) |
| Cash and cash equivalents at beginning of period | | | — | | | | 9,273 | | | | 8 | | | | — | | | | 9,281 | |
| | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | 6,831 | | | $ | 8 | | | $ | — | | | $ | 6,839 | |
| | | | | | | | | | | | | | | | |
76
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF INCOME | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| REVENUES | | $ | 1,201,895 | | | $ | 545,926 | | | $ | 395,628 | | | $ | (917,343 | ) | | $ | 1,226,106 | |
| | | | | | | | | | | | | | | | | | | | | |
| EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 2,095 | | | | 274,847 | | | | 29,216 | | | | - | | | | 306,158 | |
| Purchased power from affiliates | | | 915,261 | | | | 2,082 | | | | 63,207 | | | | (917,343 | ) | | | 63,207 | |
| Purchased power from non-affiliates | | | 160,342 | | | | - | | | | - | | | | - | | | | 160,342 | |
| Other operating expenses | | | 38,267 | | | | 104,443 | | | | 152,456 | | | | 12,190 | | | | 307,356 | |
| Provision for depreciation | | | 1,019 | | | | 30,020 | | | | 31,649 | | | | (1,315 | ) | | | 61,373 | |
| General taxes | | | 4,706 | | | | 12,626 | | | | 6,044 | | | | - | | | | 23,376 | |
| Total expenses | | | 1,121,690 | | | | 424,018 | | | | 282,572 | | | | (906,468 | ) | | | 921,812 | |
| | | | | | | | | | | | | | | | | | | | | |
| OPERATING INCOME | | | 80,205 | | | | 121,908 | | | | 113,056 | | | | (10,875 | ) | | | 304,294 | |
| | | | | | | | | | | | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income (loss) | | | 732 | | | | 31 | | | | (29,637 | ) | | | - | | | | (28,874 | ) |
| Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | �� |
| net income from equity investees | | | 119,781 | | | | (78 | ) | | | - | | | | (117,192 | ) | | | 2,511 | |
| Interest expense to affiliates | | | (34 | ) | | | (1,758 | ) | | | (1,187 | ) | | | - | | | | (2,979 | ) |
| Interest expense - other | | | (2,520 | ) | | | (21,058 | ) | | | (15,168 | ) | | | 16,219 | | | | (22,527 | ) |
| Capitalized interest | | | 51 | | | | 7,750 | | | | 2,277 | | | | - | | | | 10,078 | |
| Total other income (expense) | | | 118,010 | | | | (15,113 | ) | | | (43,715 | ) | | | (100,973 | ) | | | (41,791 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 198,215 | | | | 106,795 | | | | 69,341 | | | | (111,848 | ) | | | 262,503 | |
| | | | | | | | | | | | | | | | | | | | | |
| INCOME TAXES | | | 27,534 | | | | 39,142 | | | | 22,929 | | | | 2,217 | | | | 91,822 | |
| | | | | | | | | | | | | | | | | | | | | |
| NET INCOME | | $ | 170,681 | | | $ | 67,653 | | | $ | 46,412 | | | $ | (114,065 | ) | | $ | 170,681 | |
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (147,718 | ) | | $ | 40,130 | | | $ | 98,692 | | | $ | — | | | $ | (8,896 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (197 | ) | | | (1,081 | ) | | | — | | | | — | | | | (1,278 | ) |
| Short-term borrowings, net | | | — | | | | (9,237 | ) | | | — | | | | — | | | | (9,237 | ) |
| Other | | | (453 | ) | | | (177 | ) | | | (101 | ) | | | — | | | | (731 | ) |
| | | | | | | | | | | | | | | | |
| Net cash used for financing activities | | | (650 | ) | | | (10,495 | ) | | | (101 | ) | | | — | | | | (11,246 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (2,103 | ) | | | (174,163 | ) | | | (125,337 | ) | | | — | | | | (301,603 | ) |
| Proceeds from asset sales | | | — | | | | 114,272 | | | | — | | | | — | | | | 114,272 | |
| Sales of investment securities held in trusts | | | — | | | | — | | | | 272,094 | | | | — | | | | 272,094 | |
| Purchases of investment securities held in trusts | | | — | | | | — | | | | (284,888 | ) | | | — | | | | (284,888 | ) |
| Loans from associated companies, net | | | 250,908 | | | | 31,232 | | | | 39,540 | | | | — | | | | 321,680 | |
| Customer acquisition costs | | | (100,615 | ) | | | — | | | | — | | | | — | | | | (100,615 | ) |
| Other | | | 178 | | | | (977 | ) | | | — | | | | — | | | | (799 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) investing activities | | | 148,368 | | | | (29,636 | ) | | | (98,591 | ) | | | — | | | | 20,141 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | — | | | | (1 | ) | | | — | | | | — | | | | (1 | ) |
| Cash and cash equivalents at beginning of period | | | — | | | | 3 | | | | 9 | | | | — | | | | 12 | |
| | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | 2 | | | $ | 9 | | | $ | — | | | $ | 11 | |
| | | | | | | | | | | | | | | | |
77
57 | | |
| Item 2. | | Management’s Discussion and Analysis of Registrant and Subsidiaries |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| As of March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| ASSETS | | | | | | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | - | | | $ | 2 | | | $ | 9 | | | $ | - | | | $ | 11 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 248,994 | | | | - | | | | - | | | | - | | | | 248,994 | |
| Associated companies | | | 408,743 | | | | 199,145 | | | | 129,194 | | | | (376,278 | ) | | | 360,804 | |
| Other | | | 18,732 | | | | 12,856 | | | | 50,071 | | | | - | | | | 81,659 | |
| Notes receivable from associated companies | | | 165,496 | | | | 209,604 | | | | 108,323 | | | | - | | | | 483,423 | |
| Materials and supplies, at average cost | | | 16,698 | | | | 327,011 | | | | 215,042 | | | | - | | | | 558,751 | |
| Prepayments and other | | | 147,780 | | | | 8,234 | | | | 4,654 | | | | - | | | | 160,668 | |
| | | | 1,006,443 | | | | 756,852 | | | | 507,293 | | | | (376,278 | ) | | | 1,894,310 | |
| | | | | | | | | | | | | | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 91,365 | | | | 5,473,440 | | | | 5,189,224 | | | | (386,022 | ) | | | 10,368,007 | |
| Less - Accumulated provision for depreciation | | | 15,030 | | | | 2,802,155 | | | | 1,973,499 | | | | (172,820 | ) | | | 4,617,864 | |
| | | | 76,335 | | | | 2,671,285 | | | | 3,215,725 | | | | (213,202 | ) | | | 5,750,143 | |
| Construction work in progress | | | 7,836 | | | | 2,110,754 | | | | 479,040 | | | | - | | | | 2,597,630 | |
| | | | 84,171 | | | | 4,782,039 | | | | 3,694,765 | | | | (213,202 | ) | | | 8,347,773 | |
| | | | | | | | | | | | | | | | | | | | | |
| INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,091,114 | | | | - | | | | 1,091,114 | |
| Investment in associated companies | | | 4,637,194 | | | | - | | | | - | | | | (4,637,194 | ) | | | - | |
| Other | | | 957 | | | | 7,367 | | | | 201 | | | | - | | | | 8,525 | |
| | | | 4,638,151 | | | | 7,367 | | | | 1,091,315 | | | | (4,637,194 | ) | | | 1,099,639 | |
| | | | | | | | | | | | | | | | | | | | | |
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes | | | 88,618 | | | | 379,772 | | | | - | | | | (401,928 | ) | | | 66,462 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Customer intangibles | | | 114,567 | | | | - | | | | - | | | | - | | | | 114,567 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Unamortized sale and leaseback costs | | | - | | | | 29,968 | | | | - | | | | 60,835 | | | | 90,803 | |
| Other | | | 80,182 | | | | 71,044 | | | | 9,188 | | | | (50,920 | ) | | | 109,494 | |
| | | | 307,615 | | | | 508,595 | | | | 31,502 | | | | (392,013 | ) | | | 455,699 | |
| | | $ | 6,036,380 | | | $ | 6,054,853 | | | $ | 5,324,875 | | | $ | (5,618,687 | ) | | $ | 11,797,421 | |
| | | | | | | | | | | | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 745 | | | $ | 696,416 | | | $ | 922,663 | | | $ | (18,640 | ) | | $ | 1,601,184 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Other | | | 100,000 | | | | - | | | | - | | | | - | | | | 100,000 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 325,118 | | | | 194,950 | | | | 190,103 | | | | (324,920 | ) | | | 385,251 | |
| Other | | | 116,942 | | | | 153,515 | | | | - | | | | - | | | | 270,457 | |
| Accrued taxes | | | 7,719 | | | | 72,449 | | | | 48,798 | | | | (62,381 | ) | | | 66,585 | |
| Other | | | 213,488 | | | | 105,682 | | | | 27,798 | | | | 46,544 | | | | 393,512 | |
| | | | 764,012 | | | | 1,223,012 | | | | 1,189,362 | | | | (359,397 | ) | | | 2,816,989 | |
| | | | | | | | | | | | | | | | | | | | | |
| CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder's equity | | | 3,589,580 | | | | 2,419,526 | | | | 2,203,491 | | | | (4,623,017 | ) | | | 3,589,580 | |
| Long-term debt and other long-term obligations | | | 1,519,155 | | | | 1,855,784 | | | | 554,591 | | | | (1,269,330 | ) | | | 2,660,200 | |
| | | | 5,108,735 | | | | 4,275,310 | | | | 2,758,082 | | | | (5,892,347 | ) | | | 6,249,780 | |
| | | | | | | | | | | | | | | | | | | | | |
| NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 984,440 | | | | 984,440 | |
| Accumulated deferred income taxes | | | - | | | | - | | | | 351,383 | | | | (351,383 | ) | | | - | |
| Accumulated deferred investment tax credits | | | - | | | | 35,590 | | | | 21,763 | | | | - | | | | 57,353 | |
| Asset retirement obligations | | | - | | | | 25,933 | | | | 910,520 | | | | - | | | | 936,453 | |
| Retirement benefits | | | 35,114 | | | | 184,060 | | | | - | | | | - | | | | 219,174 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Lease market valuation liability | | | - | | | | 250,871 | | | | - | | | | - | | | | 250,871 | |
| Other | | | 128,519 | | | | 32,266 | | | | 71,451 | | | | - | | | | 232,236 | |
| | | | 163,633 | | | | 556,531 | | | | 1,377,431 | | | | 633,057 | | | | 2,730,652 | |
| | | $ | 6,036,380 | | | $ | 6,054,853 | | | $ | 5,324,875 | | | $ | (5,618,687 | ) | | $ | 11,797,421 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING BALANCE SHEETS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| 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 | |
| Prepayments and other | | | 80,025 | | | | 18,356 | | | | 9,401 | | | | - | | | | 107,782 | |
| | | | 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 | |
| Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | |
| Customer intangibles | | | 16,566 | | | | - | | | | - | | | | - | | | | 16,566 | |
| Property taxes | | | - | | | | 27,811 | | | | 22,314 | | | | - | | | | 50,125 | |
| Unamortized sale and leaseback costs | | | - | | | | 16,454 | | | | - | | | | 56,099 | | | | 72,553 | |
| Other | | | 82,845 | | | | 71,179 | | | | 18,755 | | | | (51,114 | ) | | | 121,665 | |
| | | | 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 | |
| Other | | | 100,000 | | | | - | | | | - | | | | - | | | | 100,000 | |
| 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 | |
| Other | | | 173,015 | | | | 132,314 | | | | 16,734 | | | | 36,994 | | | | 359,057 | |
| | | | 631,474 | | | | 1,213,095 | | | | 1,256,985 | | | | (287,734 | ) | | | 2,813,820 | |
| | | | | | | | | | | | | | | | | | | | | |
| 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 | | | 1,519,339 | | | | 1,906,818 | | | | 554,825 | | | | (1,269,330 | ) | | | 2,711,652 | |
| | | | 5,033,910 | | | | 4,253,333 | | | | 2,674,313 | | | | (5,735,333 | ) | | | 6,226,223 | |
| | | | | | | | | | | | | | | | | | | | | |
| 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 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | |
| OPERATING ACTIVITIES | | $ | (147,718 | ) | | $ | 40,130 | | | $ | 98,692 | | | $ | - | | | $ | (8,896 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (197 | ) | | | (1,081 | ) | | | - | | | | - | | | | (1,278 | ) |
| Short-term borrowings, net | | | - | | | | (9,237 | ) | | | - | | | | - | | | | (9,237 | ) |
| Other | | | (453 | ) | | | (177 | ) | | | (101 | ) | | | - | | | | (731 | ) |
| Net cash used for financing activities | | | (650 | ) | | | (10,495 | ) | | | (101 | ) | | | - | | | | (11,246 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (2,103 | ) | | | (174,163 | ) | | | (125,337 | ) | | | - | | | | (301,603 | ) |
| Proceeds from asset sales | | | - | | | | 114,272 | | | | - | | | | - | | | | 114,272 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 272,094 | | | | - | | | | 272,094 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (284,888 | ) | | | - | | | | (284,888 | ) |
| Loans from associated companies, net | | | 250,908 | | | | 31,232 | | | | 39,540 | | | | - | | | | 321,680 | |
| Customer intangibles | | | (100,615 | ) | | | - | | | | - | | | | - | | | | (100,615 | ) |
| Other | | | 178 | | | | (977 | ) | | | - | | | | - | | | | (799 | ) |
| Net cash provided from (used for) investing activities | | | 148,368 | | | | (29,636 | ) | | | (98,591 | ) | | | - | | | | 20,141 | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | (1 | ) | | | - | | | | - | | | | (1 | ) |
| Cash and cash equivalents at beginning of period | | | - | | | | 3 | | | | 9 | | | | - | | | | 12 | |
| Cash and cash equivalents at end of period | | $ | - | | | $ | 2 | | | $ | 9 | | | $ | - | | | $ | 11 | |
| FIRSTENERGY SOLUTIONS CORP. | |
| | | | | | | | | | | | | | | | |
| CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | |
| (Unaudited) | |
| | | | | | | | | | | | | | | | |
| For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In thousands) | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| NET CASH PROVIDED FROM OPERATING ACTIVITIES | | $ | 200,420 | | | $ | 28,545 | | | $ | 118,902 | | | $ | - | | | $ | 347,867 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | - | | | | 100,000 | | | | - | | | | - | | | | 100,000 | |
| Short-term borrowings, net | | | 98,881 | | | | 88,308 | | | | 434,105 | | | | - | | | | 621,294 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (1,189 | ) | | | (626 | ) | | | (334,101 | ) | | | - | | | | (335,916 | ) |
| Net cash provided from financing activities | | | 97,692 | | | | 187,682 | | | | 100,004 | | | | - | | | | 385,378 | |
| | | | | | | | | | | | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (358 | ) | | | (198,631 | ) | | | (213,816 | ) | | | - | | | | (412,805 | ) |
| Proceeds from asset sales | | | - | | | | 7,573 | | | | - | | | | - | | | | 7,573 | |
| Sales of investment securities held in trusts | | | - | | | | - | | | | 351,414 | | | | - | | | | 351,414 | |
| Purchases of investment securities held in trusts | | | - | | | | - | | | | (356,904 | ) | | | - | | | | (356,904 | ) |
| Loans to associated companies, net | | | (297,641 | ) | | | (6,322 | ) | | | - | | | | - | | | | (303,963 | ) |
| Other | | | (113 | ) | | | (18,852 | ) | | | 400 | | | | - | | | | (18,565 | ) |
| Net cash used for investing activities | | | (298,112 | ) | | | (216,232 | ) | | | (218,906 | ) | | | - | | | | (733,250 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | - | | | | (5 | ) | | | - | | | | - | | | | (5 | ) |
| Cash and cash equivalents at beginning of period | | | - | | | | 39 | | | | - | | | | - | | | | 39 | |
| Cash and cash equivalents at end of period | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | |
13. INTANGIBLE ASSETS
FES has acquired certain customer contract rights, which were capitalized as intangible assets. These rights allow FES to supply electric generation needs to customers and are being amortized ratably over the term of the related contracts. Net intangible assets of $114 million are included in other assets on the FirstEnergy Consolidated Balance Sheet as of March 31, 2010.
For the three months ended March 31, 2010, amortization expense was approximately $3 million.
14. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.
As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement, Merger Sub will merge with and into Allegheny Energy with Allegheny Energy 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 Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receive 0.667 of a share of common stock of FirstEnergy and Allegheny Energy stockho lders will own approximately 27% of the combined company. The Merger Agreement was unanimously approved by both companies’ Boards of Directors.
Pursuant to the Merger Agreement, completion of the merger is conditioned upon, among other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stock to be issued in connection with the merger, as well as expiration or termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
On March 23, 2010, FirstEnergy filed with the SEC a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relating to the proposed merger (Registration Statement). After the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.
The companies expect to make their filing with the FERC under Section 203 of the FPA and the applications for clearance under HSR in May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and Virginia are expected to be filed in the second quarter of 2010.
In connection with the proposed merger, during the first quarter of 2010, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of expenses associated with merger transactions costs. These costs are expensed as incurred.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy 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 Energy’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 Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC in conn ection with the merger.
Item 2. Management's Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT'SMANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. in the first quarter of 20102011 were $50 million, or basic and diluted earnings of $0.15 per share of common stock, compared with $155 million, or basic and diluted earnings of $0.51 per share of common stock compared with $119 million, or basic and diluted earnings of $0.39 per share of common stock in the first quarter of 2009.2010. The increase in earnings resulted principally from decreased regulatory charges and increased investment income, partially offset by derivative mark-to-market adjustments, and increased fuel and purchased power costs and net amortization of regulatory assets.principal reasons for the decreases are summarized below.
| | | | | |
| Change in Basic Earnings Per Share From Prior Year | | 2011 | |
| | | | | |
| Basic earnings Per Share — First Quarter 2010 | | $ | 0.51 | |
| Non-core asset sales/impairments | | | (0.03 | ) |
| Trust securities impairments | | | 0.01 | |
| Mark-to-market adjustments | | | 0.09 | |
| Income tax charge from healthcare legislation — 2010 | | | 0.04 | |
| Regulatory charges — 2011 | | | (0.04 | ) |
| Regulatory charges — 2010 | | | 0.08 | |
| Merger-related costs | | | (0.34 | ) |
| Revenues | | | (0.26 | ) |
| Fuel and purchased power | | | 0.21 | |
| Transmission expense | | | (0.07 | ) |
| Amortization of regulatory assets, net | | | 0.07 | |
| Interest expense | | | 0.03 | |
| Merger accounting — commodity contracts | | | (0.04 | ) |
| Allegheny earnings contribution* | | | 0.13 | |
| Additional shares issued | | | (0.06 | ) |
| Other | | | (0.18 | ) |
| | | | |
| Basic earnings Per Share — First Quarter 2011 | | $ | 0.15 | |
| | | | |
| | |
| * | | Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately. |
| Change in Basic Earnings Per Share From Prior Year | | | 2010 | |
| | | | | |
| Basic Earnings Per Share – First Quarter 2009 | | | | $ | 0.39 | |
| Non-core asset sales/impairments - 2010 | | | (0.02 | ) |
| Trust securities impairments | | | 0.05 | |
| Regulatory charges – 2009 | | | 0.55 | |
| Regulatory charges – 2010 | | | (0.08 | ) |
| Derivative mark-to-market adjustment - 2010 | | | (0.11 | ) |
| Organizational restructuring - 2009 | | | 0.05 | |
| Merger transaction costs - 2010 | | | (0.03 | ) |
| Income tax resolution - 2009 | | | (0.04 | ) |
| Income tax charge from healthcare legislation - 2010 | | | (0.04 | ) |
| Revenues | | | (0.07 | ) |
| Fuel and purchased power | | | (0.13 | ) |
| Transmission expense | | | 0.10 | |
| Amortization of regulatory assets, net | | | (0.17 | ) |
| Investment income | | | 0.01 | |
| Other expenses | | | | 0.05 | |
| Basic Earnings Per Share – First Quarter 2010 | | | | $ | 0.51 | |
Financial Matters
Proposed Merger with Allegheny Energy, Inc.
On February 10, 2010,25, 2011, the merger between FirstEnergy entered into anand Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger (Merger Agreement) withbetween FirstEnergy, Element Merger Sub.Sub, Inc., a Maryland corporation and itsa wholly-owned subsidiary of FirstEnergy (Merger Sub), and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the terms and subject to the conditions set forth in the Merger Agreement,AE, Merger Sub will mergemerged with and into Allegheny EnergyAE with Allegheny EnergyAE continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. Pursuant to the Merger Agreement, upon the closingAs part of the merger, each issued and outstanding share of Allegheny Energy common stock, including grants of restricted common stock, will automatically be converted into the right to receiveAE shareholders received 0.667 of a share of FirstEnergy common stock of FirstEnergy and Allegheny Energy stockholders will own approximately 27%for each AE share outstanding as of the combined company. Basedmerger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share, or $4.7 billion in the aggregate. FirstEnergy will also assume all outstanding Allegheny Energy debt. The price per share represents a premium of 31.6% to the closing stock price of Allegheny Energy on February 10, 2010, and a 22.3% premium to the average stock price of Allegheny over the last 60 days ending February 10, 2010.
same basis.
In connection with the proposed merger, FirstEnergy recorded approximately $82 million and $14 million of merger transaction costs during the first quarter of 2011 and 2010, respectively. FirstEnergy’s consolidated financial statements include Allegheny’s results of operations and financial position effective February 25, 2011. In addition, in the three months ended March 31, 2011, $75 million of pre-tax merger integration costs and $24 million of charges from merger settlements approved by regulatory agencies have been recognized. Charges resulting from merger settlements are not expected to be material in future periods.
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Operational Matters
Fremont Energy Center
On March 14, 2011, FirstEnergy recorded approximately $14.2 million ($9.6 million after tax) of merger transactions costs. These costs are expensed as incurred.
Pursuantentered into a definitive agreement to sell Fremont Energy Center (707 MW) to American Municipal Power, Inc. (AMP). Under the Merger Agreement, completionterms of the mergeragreement, AMP will purchase Fremont Energy Center for approximately $485 million, based on 685 MW of output. The purchase price would be incrementally increased, not to exceed an additional $16 million, to reflect additional output and transmission export capacity to its nameplate capacity of 707 MW. In addition, AMP would reimburse FirstEnergy up to $25.3 million for construction costs incurred from February 1, 2011 through the closing date. On April 19, 2011, FGCO filed an application with the FERC for authorization to sell the Fremont Energy Center, including related capacity supply obligations, to AMP. The transaction is conditioned upon, amongexpected to close in July 2011.
Perry Refueling
FENOC shutdown the Perry Nuclear Plant on April 18, 2011, for scheduled refueling and maintenance. During the outage 284 of the 748 fuel assemblies will be exchanged and maintenance safety inspections will be conducted while the unit is off line. Preventative maintenance to ensure continued safe and reliable operations will be preformed, including replacing several control rod blades, rewinding the generator and testing more than 100 valves. On April 25, 2011, the NRC began a Special Inspection to review the circumstances surrounding work activities to remove a source range monitor from the reactor core on April 22, 2011.
Beaver Valley Refueling
On April 11, 2011, FENOC announced that Beaver Valley Unit 2 (911 MW) returned to service following a March 7, 2011 shutdown for refueling and maintenance. During the outage 60 of the 157 fuel assemblies were exchanged, safety inspections were conducted, and numerous maintenance and improvement projects were completed.
Seneca Plant Maintenance
In March 2011, FirstEnergy announced that the Seneca Pumped-Storage Hydroelectric facility (451 MW) will repave its Upper Reservoir, overhaul the shutoff valves and perform routine maintenance activities.
TrAIL
On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other things, shareholder approval of both companies, the SEC’s clearance of a registration statement registering the FirstEnergy common stocksegments are planned to be issuedenergized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
Signal Peak
On March 16, 2011, Signal Peak Energy received a letter from the MSHA indicating that its mine is no longer being considered for a pattern of potential violations notice.
Financial Matters
On March 16, 2011, Penelec and Met-Ed extended for three years the LOCs supporting two series of PCRBs currently outstanding in a variable interest rate mode totaling $49 million.
On March 17 and April 1, 2011, FES and Penelec completed the remarketing of six series of PCRBs totaling $328 million. Each of these series either remained in or was converted to a variable interest rate mode supported by a three-year bank LOC. In connection with the merger, as well as expiration or terminationremarketings, approximately $207 million aggregate principal amount of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements ActFMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of 1976FMBs previously delivered to secure PCRBs are expected to be cancelled on May 31, 2011.
On March 29, 2011, FES repaid a $100 million two-year term loan facility secured by FMBs that was scheduled to mature March 31, 2011. On April 8, 2011, FirstEnergy entered into a new $150 million unsecured term loan with an April 2013 maturity.
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Regulatory Matters
Ohio Energy Efficiency (EE) and approval by the FERC, the Maryland Public Service Commission, PPUC, the Virginia State Corporation Commission and the West Virginia Public Service Commission. The Merger Agreement also contains certain termination rights for both FirstEnergy and Allegheny Energy, and further provides for the payment of fees and expenses upon termination under specified circumstances.
Peak Demand Reduction (DR) Portfolio Plan
On March 23, 2010, FirstEnergy filed2011, the PUCO approved the three-year EE and DR portfolio plan for the Ohio Companies. The Ohio Companies’ plan was developed to comply with the SECEE mandate in Ohio’s SB 221, passed in 2008. This law requires that utilities in Ohio reduce energy usage by 22.2 percent by 2025 and peak demand by 7.75 percent by 2018, develop a registration statement on Form S-4 containing a preliminary joint proxy statement/prospectus relatingportfolio plan, and meet annual benchmarks to measure progress.
Penn SREC
On March 11, 2011, the proposed merger (Registration Statement). AfterPPUC approved the Registration Statement has been declared effective by the SEC, FirstEnergy and Allegheny Energy expect to send the joint proxy statement/prospectus contained in the Registration Statement to their respective shareholders and each hold a special shareholder meeting to approve proposals related to the merger.
The companies expect to make their filing with the FERC under Section 203results of the FPA andPenn procurement of SRECs to meet Pennsylvania’s Alternative Energy Portfolio Standards through 2020. One SREC represents the applicationssolar renewable energy attributes of one MWH of generation from a solar generating facility. Penn contracted for clearance under19,800 SREC’s. This purchase of SRECs is equivalent to approximately 2,200 MWH of solar power generation annually over the HSR innext nine years. The average cost is $199.09 per SREC, with deliveries scheduled for June 2011 through May 2010. Applications for state regulatory approval in Pennsylvania, Maryland, West Virginia and Virginia are expected to be filed in2020.
FIRSTENERGY’S BUSINESS
With the second quarter of 2010.
FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first half of 2011. Although FirstEnergy and Allegheny Energy 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 Energy’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 Energy and FirstEnergy. Further information concerning the proposed merger is included in the Registration Statement filed by FirstEnergy with the SEC i n connection with the merger.
Non-core asset sales/Impairments
During the first quarter of 2010, FirstEnergy recorded charges of approximately $9.2 million ($6.0 million after-tax) associated with sale of FGCO’s 340-MW Sumpter Plant and the termination of gas drilling participation rights associated with certain previously owned Ohio properties.
Derivative mark-to-market adjustments
As a resultcompletion of the continued decline in electricity prices, mark-to-market adjustments relating to certain purchased power contracts increased expensesAllegheny merger in the first quarter of 20102011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting utilized by $51.9 million ($32.5 million after tax). From December 31, 2009FirstEnergy’s chief executive officer (its chief operating decision maker) to March 31, 2010 forward aroundregularly assess the clock electricity prices per MWH have declined approximately 14%.
Elimination of retiree prescription drug tax benefits
As a resultperformance of the Patient Protectionbusiness and Affordable Care Actallocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and the Health Care and Education Affordability Reconciliation Act signed into law on March 23, 2010 and March 30, 2010, respectively, beginning in 2011 the tax deduction available to FirstEnergy will be reducedCompetitive Energy Services.
Prior to the extentchange in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included FirstEnergy’s then eight existing utility operating companies that drug costs are reimbursed undertransmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” segment consisted of corporate items and other businesses that were below the Medicare Part D retiree subsidy program. Duringquantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.
The changes in FirstEnergy’s reportable segments during the first quarter of 2010, FirstEnergy recognized a one-time adjustment of approximately $12.6 million to reduce the deferred tax asset associated with these subsidies.
Operational Matters
Davis Besse Refueling
On February 28, 2010, the Davis Besse Nuclear Plant (908-MW) began a refueling outage to exchange 762011 consisted primarily of the 177 fuel assembliesfollowing:
Energy Delivery Services was renamed Regulated Distribution and conduct numerous safety inspections. During the outage, it was determined that modificationsoperations of MP, PE and WP, which were needed to 16acquired as part of the 69 control rod drive mechanism nozzles (CDRM) that penetratedmerger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the reactor vessel head. Further evaluation“Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and testing identified 8 additional nozzles requiring modifications. Additional testing will be conducted following the modificationoperations of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restartTrAIL Company and FirstEnergy’s interest in July, 2010.
PJM RTO Integration
From March 15-19, 2010, PJM conducted two competitive auctions FRR Integration Auctions on behalfPATH; TrAIL and PATH were acquired as part of the Ohio Companiesmerger with Allegheny. The transmission assets and Penn to secure electric capacity for delivery years June 1, 2011 through May 31, 2012,operations of JCP&L, Met-Ed, Penelec, MP, PE and June 1, 2012 through May 21, 2013. Monitoring Analytics, LLC, acting asWP remain within the PJM Market Monitor, certified the auction results on March 26, 2010. In the 2011/2012 auction, 27 suppliers participated, and 12,583 MW of capacity cleared at a price of $108.89/MW-day. The 2012/2013 auction had 28 market participants, with 13,038 MW of capacity clearing at a price of $20.46/MW-day. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers.
Regulated Distribution segment.
64
AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.
Regulatory Matters - Ohio
New Electric Security Plan
On March 23, 2010, the Ohio Companies filed a new ESP with the PUCO. The ESP was filed as a Stipulation and Recommendation and incorporated the substantial record developedFinancial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.
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The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Companies’ earlier filingPennsylvania, West Virginia, Virginia, Maryland, New Jersey and New York, and purchases power for an MRO. its POLR and default service requirements in Ohio, Pennsylvania and New Jersey. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.
The ESP is a three-year plan that would begin June 1, 2011, would provide for a CBPRegulated Distribution segment’s 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 procure generation supply forretail customers that choosewho have not to shop withselected an alternative supplier with more(POLR or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.
The Regulated Independent Transmission segment transmits electricity through transmission lines. Its revenues are primarily derived from the formula rate levels for customers, timely recovery of PUCO-authorized charges, deferral of certain costs and promotes energy efficiencya return on debt and economic development. The Ohio Companies have requested PUCO approval by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. Inequity for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the filing , FirstEnergy recorded approximately $39.5 million ($25.2 million after tax) of regulatory asset impairmentstransmission system. Its results reflect the net PJM and MISO transmission expenses related to the ESP.
delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets currently dedicated to MISO are scheduled to be integrated into the PJM market. This integration brings all of FirstEnergy’s assets into one RTO.Regulatory Matters -The Competitive Energy Services segment, through FES, 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. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.
Met-EdThe Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and Penelec Transmission Service Charge
On March 3, 2010, Met-EdAE Supply’s interest in AGC. AE Supply owns, operates and Penelec received an Ordercontrols the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the PPUC which deniedBath County generation facility to AE Supply and MP.
This business segment controls approximately 20,000 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 less the recoveryrelated costs of marginalelectricity generation, including purchased power and net transmission losses through the TSC rider for the period June 1, 2007 through March 31, 2008(including congestion) and instructed Met-Edancillary costs charged by PJM and PenelecMISO to work with the parties and file a petition to retain any over-collection, with interest, until 2011, when Met-Ed and Penelec’s generation rate caps expire. In responsedeliver energy to the Order, on March 18, 2010, Met-Edsegment’s customers.
The Other segment contains corporate items and Penelec requestedother businesses that are below the PPUC grantquantifiable threshold for separate disclosure as a stay of its Order, with such stay being granted by the PPUC on March 25, 2010 until December 31, 2010, allowing for the continued collection of marginal losses subject to refund. On April 1, 2010, Met-Ed and Penelec filed with the Commonwealth Court of Pennsylvania a Petition for Review of the PPUC’s Order disallowing the recovery of ma rginal transmission losses in the TSC. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penlec believe they should prevail on appeal and should recover marginal transmission losses for the period prior to January 1, 2011.reportable segment.
FIRSTENERGY'S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through two core business segments (see Results of Operations).
· | Energy Delivery Services transmits and distributes electricity through our 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 PLR and default service requirements in Ohio, Pennsylvania and New Jersey. Its revenues are primarily derived from the delivery of electricity within our 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 certain fuel costs.
|
· | Competitive Energy Services 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 PLR and default service requirements of our Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland and Michigan. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW 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 char ged by PJM and MISO to deliver energy to the segment’s customers.
|
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 1113 to the consolidated financial statements. Earnings available to FirstEnergy Corp. by major business segment were as follows:
| | | | | | | | | | | | | |
| | | Three Months Ended | | | | |
| | | March 31 | | | Increase | |
| | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions, except per share data) | |
Earnings By Business Segment: | | | | | | | | | | | | |
| Regulated Distribution | | $ | 96 | | | $ | 103 | | | $ | (7 | ) |
| Competitive Energy Services | | | 5 | | | | 69 | | | | (64 | ) |
| Regulated Independent Transmission | | | 13 | | | | 12 | | | | 1 | |
| Other and reconciling adjustments* | | | (64 | ) | | | (29 | ) | | | (35 | ) |
| | | | | | | | | | |
| Total | | $ | 50 | | | $ | 155 | | | $ | (105 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Basic Earnings Per Share | | $ | 0.15 | | | $ | 0.51 | | | $ | (0.36 | ) |
Diluted Earnings Per Share | | $ | 0.15 | | | $ | 0.51 | | | $ | (0.36 | ) |
| | | Three Months Ended | | | |
| | | March 31 | | Increase | |
| | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions, except per share data) | |
| Earnings By Business Segment: | | | | | | | |
| Energy delivery services | | $ | 114 | | $ | (18 | ) | $ | 132 | |
| Competitive energy services | | | 76 | | | 155 | | | (79 | ) |
| Other and reconciling adjustments* | | | (35 | ) | | (18 | ) | | (17 | ) |
| Total | | $ | 155 | | $ | 119 | | $ | 36 | |
| | | | | | | | | | | |
| Basic Earnings Per Share | | $ | 0.51 | | $ | 0.39 | | $ | 0.12 | |
| Diluted Earnings Per Share | | $ | 0.51 | | $ | 0.39 | | $ | 0.12 | |
| | | | | | | | | | | |
| * Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. | |
| | |
| * | | Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. |
Summary of Results of Operations –— First Quarter 20102011 Compared with First Quarter 2009
2010
Financial results for FirstEnergy'sFirstEnergy’s major business segments in the first quarter of 20102011 and 20092010 were as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| First Quarter 2011 Financial Results | | Distribution | | | Services | | | Transmission | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 2,175 | | | $ | 1,162 | | | $ | — | | | $ | — | | | $ | 3,337 | |
| Other | | | 93 | | | | 92 | | | | 67 | | | | (45 | ) | | | 207 | |
| Internal | | | — | | | | 343 | | | | — | | | | (311 | ) | | | 32 | |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | 2,268 | | | | 1,597 | | | | 67 | | | | (356 | ) | | | 3,576 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 24 | | | | 429 | | | | — | | | | — | | | | 453 | |
| Purchased power | | | 1,179 | | | | 318 | | | | — | | | | (311 | ) | | | 1,186 | |
| Other operating expenses | | | 386 | | | | 648 | | | | 17 | | | | (18 | ) | | | 1,033 | |
| Provision for depreciation | | | 116 | | | | 88 | | | | 10 | | | | 6 | | | | 220 | |
| Amortization of regulatory assets | | | 129 | | | | — | | | | 3 | | | | — | | | | 132 | |
| Deferral of new regulatory assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| General taxes | | | 176 | | | | 44 | | | | 8 | | | | 9 | | | | 237 | |
| Impairment of long-lived assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | 2,010 | | | | 1,527 | | | | 38 | | | | (314 | ) | | | 3,261 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 258 | | | | 70 | | | | 29 | | | | (42 | ) | | | 315 | |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 25 | | | | 6 | | | | — | | | | (10 | ) | | | 21 | |
| Interest expense | | | (132 | ) | | | (78 | ) | | | (9 | ) | | | (12 | ) | | | (231 | ) |
| Capitalized interest | | | 1 | | | | 10 | | | | — | | | | 7 | | | | 18 | |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (106 | ) | | | (62 | ) | | | (9 | ) | | | (15 | ) | | | (192 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 152 | | | | 8 | | | | 20 | | | | (57 | ) | | | 123 | |
| Income taxes | | | 56 | | | | 3 | | | | 7 | | | | 12 | | | | 78 | |
| | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | 96 | | | | 5 | | | | 13 | | | | (69 | ) | | | 45 | |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | (5 | ) | | | (5 | ) |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 96 | | | $ | 5 | | | $ | 13 | | | $ | (64 | ) | | $ | 50 | |
| | | | | | | | | | | | | | | | |
82
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| First Quarter 2010 Financial Results | | Distribution | | | Services | | | Transmission | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 2,398 | | | $ | 669 | | | $ | — | | | $ | — | | | $ | 3,067 | |
| Other | | | 86 | | | | 50 | | | | 57 | | | | (28 | ) | | | 165 | |
| Internal | | | — | | | | 674 | | | | — | | | | (607 | ) | | | 67 | |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | 2,484 | | | | 1,393 | | | | 57 | | | | (635 | ) | | | 3,299 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | — | | | | 334 | | | | — | | | | — | | | | 334 | |
| Purchased power | | | 1,395 | | | | 450 | | | | — | | | | (607 | ) | | | 1,238 | |
| Other operating expenses | | | 359 | | | | 352 | | | | 14 | | | | (24 | ) | | | 701 | |
| Provision for depreciation | | | 104 | | | | 77 | | | | 9 | | | | 3 | | | | 193 | |
| Amortization of regulatory assets | | | 209 | | | | — | | | | 3 | | | | — | | | | 212 | |
| Deferral of new regulatory assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| General taxes | | | 154 | | | | 37 | | | | 7 | | | | 7 | | | | 205 | |
| Impairment of long-lived assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | 2,221 | | | | 1,250 | | | | 33 | | | | (621 | ) | | | 2,883 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 263 | | | | 143 | | | | 24 | | | | (14 | ) | | | 416 | |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 26 | | | | 1 | | | | — | | | | (11 | ) | | | 16 | |
| Interest expense | | | (125 | ) | | | (56 | ) | | | (5 | ) | | | (27 | ) | | | (213 | ) |
| Capitalized interest | | | 1 | | | | 23 | | | | — | | | | 17 | | | | 41 | |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (98 | ) | | | (32 | ) | | | (5 | ) | | | (21 | ) | | | (156 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 165 | | | | 111 | | | | 19 | | | | (35 | ) | | | 260 | |
| Income taxes | | | 62 | | | | 42 | | | | 7 | | | | — | | | | 111 | |
| | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | 103 | | | | 69 | | | | 12 | | | | (35 | ) | | | 149 | |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | (6 | ) | | | (6 | ) |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 103 | | | $ | 69 | | | $ | 12 | | | $ | (29 | ) | | $ | 155 | |
| | | | | | | | | | | | | | | | |
83
| | | | | | | | | | | | | | | | | | | | | |
| Changes Between First Quarter 2011 | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| and First Quarter 2010 Financial | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| Results Increase (Decrease) | | Distribution | | | Services | | | Transmission | | | Adjustment | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | (223 | ) | | $ | 493 | | | $ | — | | | $ | — | | | $ | 270 | |
| Other | | | 7 | | | | 42 | | | | 10 | | | | (17 | ) | | | 42 | |
| Internal | | | — | | | | (331 | ) | | | — | | | | 296 | | | | (35 | ) |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | (216 | ) | | | 204 | | | | 10 | | | | 279 | | | | 277 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 24 | | | | 95 | | | | — | | | | — | | | | 119 | |
| Purchased power | | | (216 | ) | | | (132 | ) | | | — | | | | 296 | | | | (52 | ) |
| Other operating expenses | | | 27 | | | | 296 | | | | 3 | | | | 6 | | | | 332 | |
| Provision for depreciation | | | 12 | | | | 11 | | | | 1 | | | | 3 | | | | 27 | |
| Amortization of regulatory assets | | | (80 | ) | | | — | | | | — | | | | — | | | | (80 | ) |
| Deferral of new regulatory assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| General taxes | | | 22 | | | | 7 | | | | 1 | | | | 2 | | | | 32 | |
| Impairment of long-lived assets | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | (211 | ) | | | 277 | | | | 5 | | | | 307 | | | | 378 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | (5 | ) | | | (73 | ) | | | 5 | | | | (28 | ) | | | (101 | ) |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | (1 | ) | | | 5 | | | | — | | | | 1 | | | | 5 | |
| Interest expense | | | (7 | ) | | | (22 | ) | | | (4 | ) | | | 15 | | | | (18 | ) |
| Capitalized interest | | | — | | | | (13 | ) | | | — | | | | (10 | ) | | | (23 | ) |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (8 | ) | | | (30 | ) | | | (4 | ) | | | 6 | | | | (36 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | (13 | ) | | | (103 | ) | | | 1 | | | | (22 | ) | | | (137 | ) |
| Income taxes | | | (6 | ) | | | (39 | ) | | | — | | | | 12 | | | | (33 | ) |
| | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | (7 | ) | | | (64 | ) | | | 1 | | | | (34 | ) | | | (104 | ) |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | 1 | | | | 1 | |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | (7 | ) | | $ | (64 | ) | | $ | 1 | | | $ | (35 | ) | | $ | (105 | ) |
| | | | | | | | | | | | | | | | |
| | | | Energy | | | Competitive | | | Other and | | | | |
| | | | Delivery | | | Energy | | | Reconciling | | | FirstEnergy | |
| First Quarter 2010 Financial Results | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | | | (In millions) | |
| Revenues: | | | | | | | | | | | | |
| | External | | | | | | | | | | | | |
| | Electric | | $ | 2,398 | | | $ | 669 | | | $ | - | | | $ | 3,067 | |
| | Other | | | 145 | | | | 47 | | | | (27 | ) | | | 165 | |
| | Internal* | | | - | | | | 674 | | | | (607 | ) | | | 67 | |
| Total Revenues | | | 2,543 | | | | 1,390 | | | | (634 | ) | | | 3,299 | |
| | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| | Fuel | | | - | | | | 337 | | | | (3 | ) | | | 334 | |
| | Purchased power | | | 1,395 | | | | 450 | | | | (607 | ) | | | 1,238 | |
| | Other operating expenses | | | 380 | | | | 347 | | | | (26 | ) | | | 701 | |
| | Provision for depreciation | | | 113 | | | | 66 | | | | 14 | | | | 193 | |
| | Amortization of regulatory assets | | | 212 | | | | - | | | | - | | | | 212 | |
| | Deferral of new regulatory assets | | | - | | | | - | | | | - | | | | - | |
| | General taxes | | | 162 | | | | 35 | | | | 8 | | | | 205 | |
| Total Expenses | | | 2,262 | | | | 1,235 | | | | (614 | ) | | | 2,883 | |
| | | | | | | | | | | | | | | | | | |
| Operating Income | | | 281 | | | | 155 | | | | (20 | ) | | | 416 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| | Investment income | | | 25 | | | | 1 | | | | (10 | ) | | | 16 | |
| | Interest expense | | | (124 | ) | | | (53 | ) | | | (36 | ) | | | (213 | ) |
| | Capitalized interest | | | 1 | | | | 20 | | | | 20 | | | | 41 | |
| Total Other Expense | | | (98 | ) | | | (32 | ) | | | (26 | ) | | | (156 | ) |
| | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 183 | | | | 123 | | | | (46 | ) | | | 260 | |
| Income taxes | | | 69 | | | | 47 | | | | (5 | ) | | | 111 | |
| Net Income (Loss) | | | 114 | | | | 76 | | | | (41 | ) | | | 149 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (6 | ) | | | (6 | ) |
| Earnings available to FirstEnergy Corp. | | $ | 114 | | | $ | 76 | | | $ | (35 | ) | | $ | 155 | |
| | | | | | | | | | | | | | | | | | |
| * | 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 | | | Competitive | | | Other and | | | | |
| | | Delivery | | | Energy | | | Reconciling | | | FirstEnergy | |
| First Quarter 2009 Financial Results | | Services | | | Services | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | |
| External | | | | | | | | | | | | |
| Electric | | $ | 2,861 | | | $ | 280 | | | $ | - | | | $ | 3,141 | |
| Other | | | 160 | | | | 55 | | | | (22 | ) | | | 193 | |
| Internal | | | - | | | | 893 | | | | (893 | ) | | | - | |
| Total Revenues | | | 3,021 | | | | 1,228 | | | | (915 | ) | | | 3,334 | |
| | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| Fuel | | | - | | | | 312 | | | | - | | | | 312 | |
| Purchased power | | | 1,876 | | | | 160 | | | | (893 | ) | | | 1,143 | |
| Other operating expenses | | | 499 | | | | 355 | | | | (27 | ) | | | 827 | |
| Provision for depreciation | | | 109 | | | | 64 | | | | 4 | | | | 177 | |
| Amortization of regulatory assets, net | | | 411 | | | | - | | | | - | | | | 411 | |
| Deferral of new regulatory assets | | | (93 | ) | | | - | | | | - | | | | (93 | ) |
| General taxes | | | 170 | | | | 32 | | | | 9 | | | | 211 | |
| Total Expenses | | | 2,972 | | | | 923 | | | | (907 | ) | | | 2,988 | |
| | | | | | | | | | | | | | | | | |
| Operating Income | | | 49 | | | | 305 | | | | (8 | ) | | | 346 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| Investment income | | | 30 | | | | (29 | ) | | | (12 | ) | | | (11 | ) |
| Interest expense | | | (110 | ) | | | (28 | ) | | | (56 | ) | | | (194 | ) |
| Capitalized interest | | | 1 | | | | 10 | | | | 17 | | | | 28 | |
| Total Other Expense | | | (79 | ) | | | (47 | ) | | | (51 | ) | | | (177 | ) |
| | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | (30 | ) | | | 258 | | | | (59 | ) | | | 169 | |
| Income taxes | | | (12 | ) | | | 103 | | | | (37 | ) | | | 54 | |
| Net Income (Loss) | | | (18 | ) | | | 155 | | | | (22 | ) | | | 115 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (4 | ) | | | (4 | ) |
| Earnings available to FirstEnergy Corp. | | $ | (18 | ) | | $ | 155 | | | $ | (18 | ) | | $ | 119 | |
| | | | | | | | | | | | | | | | | |
| Changes Between First Quarter 2010 and | | | | | | | | | | | | | |
| First Quarter 2009 Financial Results | | | | | | | | | | | | | | | | |
| Increase (Decrease) | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | |
| Electric | | $ | (463 | ) | | $ | 389 | | | $ | - | | | $ | (74 | ) |
| Other | | | (15 | ) | | | (8 | ) | | | (5 | ) | | | (28 | ) |
| Internal | | | - | | | | (219 | ) | | | 286 | | | | 67 | |
| Total Revenues | | | (478 | ) | | | 162 | | | | 281 | | | | (35 | ) |
| | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | |
| Fuel | | | - | | | | 25 | | | | (3 | ) | | | 22 | |
| Purchased power | | | (481 | ) | | | 290 | | | | 286 | | | | 95 | |
| Other operating expenses | | | (119 | ) | | | (8 | ) | | | 1 | | | | (126 | ) |
| Provision for depreciation | | | 4 | | | | 2 | | | | 10 | | | | 16 | |
| Amortization of regulatory assets | | | (199 | ) | | | - | | | | - | | | | (199 | ) |
| Deferral of new regulatory assets | | | 93 | | | | - | | | | - | | | | 93 | |
| General taxes | | | (8 | ) | | | 3 | | | | (1 | ) | | | (6 | ) |
| Total Expenses | | | (710 | ) | | | 312 | | | | 293 | | | | (105 | ) |
| | | | | | | | | | | | | | | | | |
| Operating Income | | | 232 | | | | (150 | ) | | | (12 | ) | | | 70 | |
| Other Income (Expense): | | | | | | | | | | | | | | | | |
| Investment income | | | (5 | ) | | | 30 | | | | 2 | | | | 27 | |
| Interest expense | | | (14 | ) | | | (25 | ) | | | 20 | | | | (19 | ) |
| Capitalized interest | | | - | | | | 10 | | | | 3 | | | | 13 | |
| Total Other Expense | | | (19 | ) | | | 15 | | | | 25 | | | | 21 | |
| | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 213 | | | | (135 | ) | | | 13 | | | | 91 | |
| Income taxes | | | 81 | | | | (56 | ) | | | 32 | | | | 57 | |
| Net Income (Loss) | | | 132 | | | | (79 | ) | | | (19 | ) | | | 34 | |
| Noncontrolling interest loss | | | - | | | | - | | | | (2 | ) | | | (2 | ) |
| Earnings available to FirstEnergy Corp. | | $ | 132 | | | $ | (79 | ) | | $ | (17 | ) | | $ | 36 | |
Energy Delivery Services –Regulated Distribution — First Quarter 20102011 Compared with First Quarter 2009
2010
Net income increased to $114decreased by $7 million in the first quarter of 2010,2011 compared to a loss of $18 million in the first quarter of 2009,2010, primarily due to lower generation and transmission revenues and merger-related costs associated with the absence of CEI’s $216 million regulatory asset impairment in 2009,Allegheny merger, partially offset by lower purchased power costs and lower other operating expenses, partially offset by lower revenues and the absenceamortization of deferrals of new regulatory assets.
84
Revenues –
—
The decrease in total revenues resulted from the following sources:
| | | | | | | | | | | | | | |
| | | Three Months | | | | | Three Months | | | |
| | | Ended March 31 | | Increase | | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | | | 2011 | | 2010 | | (Decrease) | |
| | | (In millions) | | | (In millions) | |
Pre-merger companies | | |
| | $ | 883 | | $ | 849 | | $ | 34 | | | $ | 909 | | $ | 883 | | $ | 26 | |
| | | | | | | | | |
| | | | | | | | |
| | 1,176 | | 1,613 | | (437 | ) | | 873 | | 1,178 | | | (305 | ) |
| | | 217 | | | 188 | | | 29 | | | 116 | | 217 | | | (101 | ) |
| | | | | | | | | |
| | | 1,393 | | | 1,801 | | | (408 | ) | | 989 | | 1,395 | | | (406 | ) |
| | | | | | | | | |
| | 215 | | 318 | | (103 | ) | | 37 | | 160 | | | (123 | ) |
| | | 52 | | | 53 | | | (1 | ) | | 58 | | 46 | | 12 | |
| | | | | | | | | |
| Total pre-merger companies | | | 1,993 | | 2,484 | | | (491 | ) |
| | | | | | | | | |
| Allegheny companies | | | 275 | | — | | 275 | |
| | | | | | | | | |
| | $ | 2,543 | | $ | 3,021 | | $ | (478 | ) | | $ | 2,268 | | $ | 2,484 | | $ | (216 | ) |
| | | | | | | | | |
The changeincrease in distribution service revenues reflected higher distribution deliveries in the first quarter of 2011 compared to the same period in 2010. Distribution deliveries (excluding the Allegheny companies) increased 650,000 MWH (2.4%) to 27,538,000 MWH in the first quarter of 2011 from 26,888,000 MWH in the first quarter of 2010. The increase in distribution deliveries by customer class is summarized in the following table:
| | | | | | | | | | | | | |
| | | | | | | | | | | Increase | |
| Electric Distribution KWH Deliveries | | 2011 | | | 2010 | | | (Decrease) | |
| | | (in thousands) | | | | | | | | | |
| | | | | | | | | | | | | |
Pre-merger companies | | | | | | | | | | | | |
| Residential | | | 10,638 | | | | 10,455 | | | | 1.8 | % |
| Commercial | | | 7,929 | | | | 7,953 | | | | (0.3 | )% |
| Industrial | | | 8,841 | | | | 8,351 | | | | 5.9 | % |
| Other | | | 130 | | | | 129 | | | | 0.8 | % |
| | | | | | | | | | |
| Total pre-merger companies | | | 27,538 | | | | 26,888 | | | | 2.4 | % |
| | | | | | | | | | |
| Allegheny companies | | | 3,540 | | | | — | | | | — | |
| | | | | | | | | | |
| Total Electric Distribution MWH Deliveries | | | 31,078 | | | | 26,888 | | | | 15.6 | % |
| | | | | | | | | | |
Electric Distribution KWH Deliveries | | | |
| | | (3 | |
| | | (1 | |
| | | 7 | |
Total Distribution KWH Deliveries
| | | - | |
LowerHigher deliveries to residential customers reflected decreasedincreased weather-related usage in the first quarter of 2010,2011, as heating degree days decreasedincreased by 7%5.2% from the same period in 2009.2010. The increase in distribution deliveries to industrial customers was primarily due to a slightly recovering economyeconomic conditions in FirstEnergy'sFirstEnergy’s service territory compared to the first quarter of 2009.2010. In the industrial sector, KWH deliveries increased by 12.8% to major automotive customers (14%) and steel customers, (31%). Distribution service revenues increased primarily due4.7% to the accelerated recovery of deferred distribution costs, as approved by the PUCO, partially offset by a reduction in the transition rate for CEI effective June 1, 2009.
refinery customers and 8.4% to chemical customers.
The following table summarizes the price and volume factors contributing to the $408$406 million decrease in generation revenues in the first quarter of 20102011 compared to the first quarter of 2009:2010:
| | | | | |
| | | Increase | |
| Source of Change in Generation Revenues | | | (Decrease) | |
| | | (In millions) | |
| | | | | |
| Retail: | | | | |
| Effect of 32.4% decrease in sales volumes | | $ | (382 | ) |
| Change in prices | | | 77 | |
| | | | |
| | | | (305 | ) |
| | | | |
| Wholesale: | | | | |
| Effect of 3.9% increase in sales volumes | | | 8 | |
| Change in prices | | | (109 | ) |
| | | | |
| | | | (101 | ) |
| | | | |
| Net Decrease in Generation Revenues | | $ | (406 | ) |
| | | | |
85
| Source of Change in Generation Revenues | | Increase (Decrease) | |
| | | (In millions) | |
| Retail: | | | | |
| Effect of 30.6% decrease in sales volumes | | $ | (494 | ) |
| Change in prices | | | 57 | |
| | | | (437 | ) |
| Wholesale: | | | | |
| Effect of 14.3% decrease in sales volumes | | | (27 | ) |
| Change in prices | | | 56 | |
| | | | 29 | |
| Decrease in Generation Revenues | | $ | (408 | ) |
The decrease in retail generation sales volumes was primarily due to an increase in customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first quarter of 2011, compared to the first quarter of 2010. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries increased to 73% from 53% for the Ohio Companies increased 53%and to 40% from 2% in Met-Ed’s and Penelec’s service areas.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $123 million due to the termination of Met-Ed’s and Penelec’s transmission tariff effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.
The Allegheny companies added $275 million in revenues for the first quarter of 2011, including $69 million for distribution services, $190 million for generation sales and $16 million relating to PJM transmission revenues.
Expenses —
Total expenses decreased by $140 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $356 million lower in the first quarter of 2010 compared2011 due primarily to a decrease in sales volume requirements. The decrease in power purchased from FES reflected the same periodincrease in 2009. Retail generation prices increased primarily for CEI as a resultcustomer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the CBP auction for the service period beginning June 1, 2009.
end of 2010. The increase in wholesale generation revenues reflected higher prices forvolumes purchased from non-affiliates under Met-Ed’s and Penelec’s NUG sales togeneration procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market.
The Allegheny companies added $140 million in purchased power costs in the first quarter of 2011.
68
| | | | | |
| | | Increase | |
| Source of Change in Purchased Power | | (Decrease) | |
| | | (In millions) | |
Pre-merger companies | | | | |
| Purchases from non-affiliates: | | | | |
| Change due to decreased unit costs | | $ | (186 | ) |
| Change due to increased volumes | | | 188 | |
| | | | |
| | | | 2 | |
| | | | |
| Purchases from FES: | | | | |
| Change due to increased unit costs | | | 36 | |
| Change due to decreased volumes | | | (412 | ) |
| | | | |
| | | | (376 | ) |
| | | | |
| | | | | |
| Decrease in costs deferred | | | 18 | |
| | | | |
| Total pre-merger companies | | | (356 | ) |
| | | | |
| Purchases by Allegheny companies | | | 140 | |
| | | | |
| Net Decrease in Purchased Power Costs | | $ | (216 | ) |
| | | | |
Transmission revenuesexpenses decreased $103$98 million primarily due to lower PJM network transmission expenses and congestion costs of $110 million for Met-Ed and Penelec, partially offset by transmission expenses for the terminationAllegheny companies of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now provided for in the generation rate established under the CBP.
Expenses –
Total expenses decreased by $710 million due to the following:
· | Purchased power costs were $481 million lower in the first quarter of 2010 due to lower volume requirements, partially offset by an increase in unit costs from non-affiliates. The decrease in purchased power volumes resulted principally from the increase in customer shopping in the Ohio Companies’ service territories, as described above. |
·
| The increase in unit costs from non-affiliates in the first quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for the Ohio Companies established under the CBP auction effective June 1, 2009. |
| Source of Change in Purchased Power | | Increase (Decrease) | |
| | | (In millions) | |
| Purchases from non-affiliates: | | | | |
Change due to increased unit costs | | $ | 187 | |
Change due to decreased volumes | | | (419 | ) |
| | | | (232 | ) |
| Purchases from FES: | | | | |
Change due to decreased unit costs | | | (94 | ) |
Change due to decreased volumes | | | (152 | ) |
| | | | (246 | ) |
| | | | | |
| Increase in NUG costs deferred | | | (3 | ) |
| Net Decrease in Purchased Power Costs | | $ | (481 | ) |
· | MISO network transmission expenses were lower by $54 million due to the reduced generation sales requirements discussed above.
|
· | Administrative and general costs, including labor and employee benefit expenses, decreased $49 million as a result of cost reduction initiatives implemented since the first quarter of 2009. |
· | Other operating expenses decreased $21 million due to higher economic development expenses recognized in the first quarter of 2009 relating to the amended ESP. |
· | Forestry contractor costs were $4 million higher in the first quarter of 2010, reflecting increased vegetation management activities. |
· | Amortization of regulatory assets decreased $199 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the first quarter of 2009 and reduced CTC amortization for Met-Ed and Penelec, partially offset by a $35 million regulatory asset impairment associated with the filing of the ESP on March 23, 2010. |
· | The deferral of new regulatory assets decreased $93 million in the first quarter of 2010 principally due to the absence of CEI’s PUCO-approved purchased power cost deferral in the first quarter of 2009. |
· | Depreciation expense increased $4 million due to property additions since the first quarter of 2009. |
· | General taxes decreased $8 million primarily due to lower property and real estate taxes. |
Other Expense –
Other expense increased $19$12 million in the first quarter of 2011. 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 $16 million.
Material costs associated with maintenance activities increased $10 million in the first quarter of 2011 compared to the same period last year.
A provision for excess and obsolete material of $13 million was recognized in the first quarter of 2011 relating to revised inventory practices adopted in conjunction with the Allegheny merger.
Depreciation expense increased $12 million due to property additions since the first quarter of 2010.
86
Net amortization of regulatory assets decreased $80 million due primarily to generation-related rate deferrals for the Ohio Companies, Met-Ed and Penelec and reduced net PJM transmission cost amortization.
General taxes increased $22 million due to higher property taxes and gross receipts taxes in the first quarter of 2011.
Fuel expenses for MP were $24 million in the first quarter of 2011.
Operating expenses for the Allegheny companies were $38 million in the first quarter of 2011.
Merger-related costs incurred by the Allegheny companies were $48 million in the first quarter of 2011.
Other Expense —
Other expense increased $8 million in the first quarter of 2011 due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — First Quarter 2011 Compared with First Quarter 2010
Net income increased by $1 million in the first quarter of 2011 compared to the first quarter of 2009 primarily2010 due to higher interest expenseearnings associated with debt issuancesTrAIL and PATH ($5 million), partially offset by reduced earnings for ATSI ($4 million).
Revenues —
Revenues by transmission asset owner are shown in the Utilities since the first quarter of 2009.
69| | | | | | | | | | | | | |
| | | Three Months | | | | |
| Revenues by | | Ended March 31 | | | Increase | |
| Transmission Asset Owner | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| ATSI | | $ | 52 | | | $ | 57 | | | $ | (5 | ) |
| TrAIL | | | 14 | | | | — | | | | 14 | |
| PATH | | | 1 | | | | — | | | | 1 | |
| | | | | | | | | | |
| Total Revenues | | $ | 67 | | | $ | 57 | | | $ | 10 | |
| | | | | | | | | | |
Expenses —
Competitive Energy Services – First Quarter 2010 ComparedTotal expenses increased by $5 million due primarily to operating expenses associated with First Quarter 2009
Net income decreased to $76TrAIL and PATH, which were $3 million in the first quarter of 2010, compared to $1552011.
Other Expense —
Other expense increased $4 million in the first quarter of 2009, primarily2011 due to a decreaseadditional interest expense associated with TrAIL.
Competitive Energy Services — First Quarter 2011 Compared with First Quarter 2010
Net income decreased by $64 million in sales margins partially offset by an increase in investment income.
Revenues –
Total revenues increased $162 million inthe first quarter of 2011, compared to the first quarter of 2010, primarily due to increased transmission expense, an increaseinventory reserve adjustment, non-core asset impairments and the effect of mark-to-market adjustments.
Revenues —
Total revenues increased $204 million in the first quarter of 2011 primarily due to growth in direct and government aggregation sales volumes and salesthe inclusion of RECs,the Allegheny companies, partially offset by decreasesa decline in PLR sales to the Ohio Companies and wholesalePOLR sales.
87
The increase in total revenues resulted from the following sources:
| | | Three Months | | | |
| | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| | | | | | | | |
Direct and Government Aggregation | | | 512 | | | 91 | | | 421 | |
| | | 677 | | | 893 | | | (216 | ) |
| | | 87 | | | 189 | | | (102 | |
| | | 17 | | | 25 | | | (8) | |
| | | 67 | | | - | | | 67 | |
| | | 30 | | | 30 | | | - | |
| | | 1,390 | | | 1,228 | | | 162 | |
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended March 31 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| | | | | | | | | | | | | |
| Direct and Government Aggregation | | $ | 840 | | | $ | 512 | | | $ | 328 | |
| POLR | | | 369 | | | | 673 | | | | (304 | ) |
| Wholesale | | | 96 | | | | 91 | | | | 5 | |
| Transmission | | | 26 | | | | 17 | | | | 9 | |
| REC’s | | | 32 | | | | 67 | | | | (35 | ) |
| Other | | | 41 | | | | 33 | | | | 8 | |
| Allegheny Companies | | | 193 | | | | — | | | | 193 | |
| | | | | | | | | | |
| Total Revenues | | $ | 1,597 | | | $ | 1,393 | | | $ | 204 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct and Government Aggregation | | $ | 9 | | | | | | | | | |
| POLR | | | 68 | | | | | | | | | |
| Wholesale | | | 91 | | | | | | | | | |
| Transmission | | | 12 | | | | | | | | | |
| Other | | | 13 | | | | | | | | | |
| | | | | | | | | | | | |
| Total Revenues | | $ | 193 | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended March 31 | | | Increase | |
| MWH Sales by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In thousands) | | | | | |
| Direct | | | 9,671 | | | | 5,854 | | | | 65.2 | % |
| Government Aggregation | | | 4,310 | | | | 2,732 | | | | 57.8 | % |
| POLR | | | 5,714 | | | | 13,276 | | | | (57.0 | )% |
| Wholesale | | | 1,113 | | | | 898 | | | | 23.9 | % |
| Allegheny Companies | | | 2,636 | | | | — | | | | — | |
| | | | | | | | | | |
| Total Sales | | | 23,444 | | | | 22,760 | | | | 3.0 | % |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct | | | 145 | | | | | | | | | |
| POLR | | | 812 | | | | | | | | | |
| Structured Sales | | | 284 | | | | | | | | | |
| Wholesale | | | 1,395 | | | | | | | | | |
| | | | | | | | | | | | |
| Total Sales | | | 2,636 | | | | | | | | | |
| | | | | | | | | | | | |
The increase in direct and government aggregation revenues of $421$328 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result offrom the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well as new government aggregation contracts with communities in Ohio that provideprovided generation to approximately one1.5 million residential and small commercial customers. During January 2010, FES began supplying powercustomers at the end of March 2011 compared to approximately 425,000 NOPEC customers.1.1 million such customers at the end of March 2010. In addition, sales to residential and small commercial customers were bolstered by weather in the delivery area that was 5.2% colder than in 2010.
88
The decrease in PLRPOLR revenues of $216$304 million werewas due to lower sales volumes to the Pennsylvania and Ohio Companies, and lower unit prices, partially offset by increased sales volumesto non-associated companies and higher unit prices to the Pennsylvania Companies. The lowerParticipation in POLR auctions and RFPs are expected to continue, but the concentration of these sales volumeswill primarily be dependent on our success in our direct retail and unit pricesaggregation sales channels.
Wholesale revenues increased $5 million due to the Ohio Companies in the first quarter 2010 reflected the results of the May 2009 power procurement processes. 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 the first quarter of 2009. The increase was partially offset by lower wholesale prices. The higher sales volumes were the result of increased short term (net hourly positions) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO that were unable to Pennbe netted with short positions in PJM, due to decreased default serviceseparate settlement requirements in 2010 compared to 2009.
Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.
with each RTO.
The following tables summarize the price and volume factors contributing to changes in revenues:revenues (excluding the Allegheny companies):
Source of Change in Direct and Government Aggregation | | | |
| | | (In millions) | |
| Direct Sales: | | | | |
Effect of 471.5% increase in sales volumes | | $ | 289 | |
Change in prices | | | (30 | ) |
| | | | 259 | |
| Government Aggregation: | | | | |
Effect of an increase in sales volumes | | | 162 | |
Change in prices | | | - | |
| | | | 162 | |
| Net Increase in Direct and Gov’t Aggregation Revenues | | $ | 421 | |
Source of Change in Wholesale Revenues | | | |
| | | (In millions) | |
| PLR: | | | | |
Effect of 10.2% decrease in sales volumes | | $ | (91 | ) |
Change in prices | | | (125 | ) |
| | | | (216 | ) |
| Wholesale: | | | | |
Effect of 76.3% decrease in sales volumes | | | (112 | ) |
Change in prices | | | 10 | |
| | | | (102 | ) |
| Net Decrease in Wholesale Revenues | | $ | (318 | ) |
| | | | | |
| | | Increase | |
| Source of Change in Direct and Government Aggregation | | (Decrease) | |
| | | (In millions) | |
| Direct Sales: | | | | |
| Effect of 65.2% increase in sales volumes | | $ | 223 | |
| Change in prices | | | (4 | ) |
| | | | |
| | | | 219 | |
| | | | |
| Government Aggregation: | | | | |
| Effect of 57.8% increase in sales volumes | | | 100 | |
| Change in prices | | | 9 | |
| | | | |
| | | | 109 | |
| | | | |
| Net Increase in Direct and Government Aggregation Revenues | | $ | 328 | |
| | | | |
| | | | |
| | | Increase | |
| Source of Change in POLR Revenues | | (Decrease) | |
| | | (In millions) | |
| POLR: | | | | |
| Effect of 57.0% decrease in sales volumes | | $ | (384 | ) |
| Change in prices | | | 80 | |
| | | | |
| | | | (304 | ) |
| | | | |
| | | | |
| | | Increase | |
| Source of Change in Wholesale Revenues | | (Decrease) | |
| | | (In millions) | |
| Other Wholesale: | | | | |
| Effect of 23.9% increase in sales volumes | | | 12 | |
| Change in prices | | | (7 | ) |
| | | | |
| | | | 5 | |
| | | | |
Transmission revenues decreased $8increased $9 million due primarily to higher MISO congestion revenue. The revenues derived from the inclusionsale of the transmission-related component in the retail rates beginning in mid-2009 as a result of the CBP.
In the first three months of 2010, FES sold $67 million of RECs.
Expenses -
Total expenses increased $312RECs declined $35 million in the first quarter of 20102011.
Expenses —
Total expenses increased $277 million in the first quarter of 2011 due to the following:
Fuel costs increased $13 million primarily due to increased volumes ($31 million), partially offset by lower unit prices ($18 million). Volumes increased due to higher generation at the fossil units. Unit prices declined primarily due to improved generating unit availability at more efficient units, partially offset by increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.
· | Fuel costs increased $25 million due to increased unit prices ($36 million) partially offset by reduced generation volumes ($11 million). The increase in unit prices was due primarily to higher coal transportation charges ($10 million) and higher nuclear fuel unit prices following the refueling outages that occurred in 2009 ($16 million). |
Purchased power costs decreased $153 million due primarily to lower volumes purchased ($185 million) partially offset by higher unit costs ($32 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec. $35 million of purchased power expense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements with each RTO.
Fossil operating costs increased $1 million due primarily to higher labor costs partially offset by lower professional and contractor costs and reduced coal sale losses.
· | Purchased power costs increased $290 million due primarily to higher volumes purchased ($300 million) and power contract mark-to-market adjustments ($52 million), partially offset by lower unit costs ($62 million). |
Nuclear operating costs increased $15 million due primarily to higher labor and related benefits, partially offset by lower professional and contractor costs.
89
· | Nuclear operating costs decreased $21 million due primarily to lower labor, employee benefit expenses and professional and contractor costs. The first quarter of 2010 had fewer refueling outages than the first quarter of 2009, decreasing operating costs by approximately $5 million. |
· | Transmission expense increased $7 million due primarily to increased costs in MISO of $43 million from higher network and ancillary costs, partially offset by lower PJM transmission expense of $36 million due to lower congestion and loss expenses.
|
· | Other expense increased $5 million primarily due to increases in uncollectible customer accounts and agent fees associated with the increase in retail sales. |
· | Higher depreciation expense of $2 million was due primarily to increased property additions since the first quarter of 2009. |
· | General taxes increased $3 million due to sales taxes.
|
Transmission expenses increased $111 million due primarily to increases in PJM of $108 million from higher congestion, network, and loss expense and MISO transmission expenses of $3 million due to higher congestion costs.
General taxes increased $3 million due to an increase in revenue-related taxes.
Other expenses increased $65 million primarily due to: a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a $13 million impairment charge related to non-core assets; an $11 million increase in intercompany billings; and reduced mark-to-market adjustments of $15 million.
The inclusion of approximately one month of the Allegheny companies’ operations contributed $222 million to expenses, including a $29 million mark-to-market adjustment relating primarily to power contracts.
Other Expense –—
Total other expense in the first quarter of 20102011 was $15$30 million lowerhigher than the first quarter of 2009,2010, primarily due to a $30$35 million increase in investment income resulting from a reduction to impairmentsnet interest expense partially offset by an increase in the value of nuclear decommissioning trust investments, partially offset by a $15 millioninvestment income ($5 million). The increase in interest expense. Interest expense increasedwas primarily due to new issuancesthe inclusion of long-term debt combinedthe Allegheny companies ($20 million) and lower capitalized interest ($13 million) associated with the restructuringcompletion of existing long-term debt.the Sammis AQC project in 2010.
Other –— First Quarter 2010of 2011 Compared with First Quarter 2009of 2010
FirstEnergy’s financialFinancial 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 $17$35 million decrease in earnings available to FirstEnergy Corp. in the first three monthsquarter of 20102011 compared to the same period in 2009.2010. The decrease resulted primarily from reduced other revenues ($17 million) representing reconciling adjustments combined with increased income taxes ($12 million).
Regulatory Assets
FirstEnergy and the absence of a favorable tax resolution that occurredUtilities prepare their consolidated financial statements in the first quarter of 2009 ($13 million) and charges recorded in the first quarter of 2010 associatedaccordance with the terminationauthoritative guidance for accounting for certain types of gas drilling participation rights associatedregulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides the balance of net regulatory assets by company as of March 31, 2011 and December 31, 2010 and changes during the three months then ended:
| | | | | | | | | | | | | |
| | | March 31, | | | December 31, | | | Increase | |
| Regulatory Assets | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| OE | | $ | 385 | | | $ | 400 | | | $ | (15 | ) |
| CEI | | | 337 | | | | 370 | | | | (33 | ) |
| TE | | | 84 | | | | 72 | | | | 12 | |
| JCP&L | | | 460 | | | | 513 | | | | (53 | ) |
| Met-Ed | | | 285 | | | | 296 | | | | (11 | ) |
| Penelec | | | 179 | | | | 163 | | | | 16 | |
| Other* | | | 354 | | | | 12 | | | | 342 | |
| | | | | | | | | | |
| Total | | $ | 2,084 | | | $ | 1,826 | | | $ | 258 | |
| | | | | | | | | | |
| | |
| * | | 2011 includes $343 million related to the Allegheny companies. |
90
The following tables provide information about the composition of net regulatory assets as of March 31, 2011 and December 31, 2010 and the changes during the three months then ended:
| | | | | | | | | | | | | |
| | | March 31, | | | December 31, | | | Increase | |
| Regulatory Assets by Source | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Regulatory transition costs | | $ | 592 | | | $ | 770 | | | $ | (178 | ) |
| Customer receivables for future income taxes | | | 488 | | | | 326 | | | | 162 | |
| Loss on reacquired debt | | | 56 | | | | 48 | | | | 8 | |
| Employee postretirement benefits | | | 14 | | | | 16 | | | | (2 | ) |
| Nuclear decommissioning, decontamination and spent fuel disposal costs | | | (200 | ) | | | (184 | ) | | | (16 | ) |
| Asset removal costs | | | (220 | ) | | | (237 | ) | | | 17 | |
| MISO/PJM transmission costs | | | 280 | | | | 184 | | | | 96 | |
| Deferred generation costs | | | 574 | | | | 386 | | | | 188 | |
| Distribution costs | | | 333 | | | | 426 | | | | (93 | ) |
| Other | | | 167 | | | | 91 | | | | 76 | |
| | | | | | | | | | |
| Total | | $ | 2,084 | | | $ | 1,826 | | | $ | 258 | |
| | | | | | | | | | |
FirstEnergy had $390 million of net regulatory liabilities as of March 31, 2011, which includes $378 million of net regulatory liabilities acquired as part of the merger with AE that are primarily related to asset removal costs.
Regulatory assets that do not earn a current return totaled approximately $297 million as of March 31, 2011.
Regulatory assets not earning a current return primarily for certain previously owned Ohio properties ($5all-electric residential discounts and municipal taxes by OE, CEI and TE are approximately $53 million, after tax).
$32 million and $4 million, respectively. The timing of expected recovery of these assets cannot be determined at this time. 71Regulatory assets not earning a current return primarily for regulatory transition costs by Met-Ed and Penelec are approximately $114 million and $5 million, respectively, and are expected to be recovered by 2020.
Regulatory assets not earning a current return primarily for certain storm damage costs and pension and postretirement benefits by JCP&L are approximately $37 million. The timing of expected recovery of these assets cannot be determined at this time.
Regulatory assets not earning a current return primarily for certain deferred generation costs are approximately $52 million by FirstEnergy’s other utility subsidiaries are expected to be recovered over various periods though 2012.
CAPITAL RESOURCES AND LIQUIDITY
As of March 31, 2011, FirstEnergy had cash and cash equivalents of approximately $1.1 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.
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy'sFirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2010 and in subsequent years,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 during those periods.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 liquidity position and ability to fund its 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 in the competitive generation markets, 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 and a successful merger integration.
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As of March 31, 2010, FirstEnergy's2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($0.9 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt.debt and short-term borrowings. Currently payable long-term debt as of March 31, 2010,2011, included the following (in millions):
| | | | | |
| Currently Payable Long-term Debt | | | | |
PCRBs supported by bank LOCs(1) | | $ | 827 | |
FGCO and NGC unsecured PCRBs(1) | | | 141 | |
| Penelec unsecured PCRBs | | | 25 | |
| FirstEnergy Corp. unsecured note | | | 250 | |
| NGC collateralized lease obligation bonds | | | 50 | |
| Sinking fund requirements | | | 49 | |
| Other notes | | | 43 | |
| | | | |
| | | $ | 1,385 | |
| | | | |
| Currently Payable Long-term Debt | | | |
PCRBs supported by bank LOCs(1) | | $ | 1,553 | |
FGCO and NGC unsecured PCRBs(1) | | 65 | |
Penelec FMBs(2) | | 24 | |
| NGC collateralized lease obligation bonds | | 44 | |
| Sinking fund requirements | | 34 | |
Other notes(2) | | 63 | |
| | | $ | 1,783 | |
| | | | |
(1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Mature in November 2010. | |
| | |
| (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 $0.9 billion$486 million of short-term borrowings as of March 31, 20102011 and $1.2 billion$700 million as of December 31, 2009. FirstEnergy's2010. FirstEnergy’s available liquidity as of April 30, 2010,25, 2011, is summarized in the following table:
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Available | |
| Company | | Type | | Maturity | | Commitment | | | Liquidity | |
| | | | | | | | | (In millions) | |
FirstEnergy(1) | | Revolving | | Aug. 2012 | | $ | 2,750 | | | $ | 1,983 | |
| AE | | Revolving | | Apr. 2013 | | | 250 | | | | 247 | |
AE Supply(2) | | Revolving | | Various | | | 1,050 | | | | 1,000 | |
| FE Utilities & TrAIL | | Revolving | | 2013 | | | 910 | | | | 475 | |
| | | | | | | | | | | | | |
| | | | | Subtotal | | $ | 4,960 | | | $ | 3,705 | |
| | | | | Cash | | | — | | | | 1,134 | |
| | | | | | | | | | | | | |
| | | | | Total | | $ | 4,960 | | | $ | 4,839 | |
| | | | | | | | | | | | | |
| Company | | Type | | Maturity | | Commitment | | Available Liquidity as of April 30, 2010 | |
| | | | | | | (In millions) | |
FirstEnergy(1) | | Revolving | | Aug. 2012 | | $ | 2,750 | | $ | 1,380 | |
| FirstEnergy Solutions | | Bank line | | Mar. 2011 | | | 100 | | | - | |
| Ohio and Pennsylvania Companies | | Receivables financing | | Various(2) | | | 345 | | | 272 | |
| | | | | Subtotal | | $ | 3,195 | | $ | 1,652 | |
| | | | | Cash | | | - | | | 357 | |
| | | | | Total | | $ | 3,195 | | $ | 2,009 | |
| | | | | | | | | | | | |
(1) FirstEnergy Corp. and subsidiary borrowers. (2) Ohio - $200 million (March – May 2010), $250 million (June 2010 – February 2011) matures March 30, 2011; Pennsylvania - $145 million matures December 17, 2010 | |
| | |
| (1) | | FirstEnergy Corp. and subsidiary borrowers. |
|
| (2) | | Includes $50 million for AGC. |
Revolving Credit Facility
Facilities
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.
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The following table summarizes the borrowing sub-limits for each borrower under the facility,facilities, 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 March 31, 2010:2011:
| | | | | | | | | |
| | | 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 | | | | 33 | (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) | | | 50 | |
| | | Revolving | | Regulatory and | |
| | | Credit Facility | | Other Short-Term | |
| | | | | |
| | | (In millions) | |
| FirstEnergy | | $ | 2,750 | | $ | - | (1) |
| FES | | | 1,000 | | | - | (1) |
| OE | | | 500 | | | 500 | |
| Penn | | | 50 | | | 33 | (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) | | 50 | |
| | |
| (1) | | No regulatory approvals, statutory or charter limitations applicable.limitations. |
|
| (2) | | Excluding amounts whichthat may be borrowed under the regulated companies'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. 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 $2.75 billion 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'sborrower’s borrowing sub-limit.
The $2.75 billion 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 March 31, 2010, FirstEnergy's2011, FirstEnergy’s and its subsidiaries'subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
| | | | |
| Borrower | | | | |
FirstEnergy(1) | | 61.2 | 57.6 | % |
| FES | | 54.2 | 53.3 | % |
| OE | | 54.3 | 55.0 | % |
| Penn | | 31.9 | 35.0 | % |
| CEI | | 59.8 | 56.4 | % |
| TE | | 59.5 | 58.1 | % |
| JCP&L | | 36.1 | 34.5 | % |
| Met-Ed | | 39.5 | 44.3 | % |
| Penelec | | 54.2 | 54.5 | % |
| ATSI | | 51.1 | 49.6 | % |
(1)As of March 31, 2010, FirstEnergy could issue additional debt of approximately
$2.8 billion, or recognize a reduction in equity of approximately $1.5As of March 31, 2011, FirstEnergy could issue additional debt of approximately $7.1 billion, or recognize a reduction in equity of approximately $3.8 billion, and
remain within the limitations of the financial covenants required by its $2.75 billion revolving credit facility. |
The $2.75 billion revolving credit facility, does not contain provisions that either restrict the ability to borrow or accelerate repaymentpayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in "pricing“pricing grids,"” whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
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In addition to the $2.75 billion revolving credit facility, FirstEnergy also has access to an additional $2.2 billion of revolving credit facilities relating to the Allegheny companies. The following table summarizes the borrowing sub-limits for each borrower under the facilities as of March 31, 2011: 73| | | | | |
| | | Revolving | |
| | | Credit Facility | |
| Borrower | | Sub-Limit | |
| | | (In millions) | |
| AE | | $ | 250 | |
| AE Supply | | | 1,000 | |
| MP | | | 110 | |
| PE | | | 150 | |
| WP | | | 200 | |
| AGC | | | 50 | |
| TrAIL | | | 450 | |
Under the terms of their individual credit facilities, outstanding debt of AE Supply, MP, PE, WP and AGC may not exceed 65% of the sum of their debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.
FirstEnergy, the Utilities, FES and AESC are currently pursuing an aggregate of up to $4.0 billion in new multi-year revolving credit facilities to replace a portion of the existing facilities described above.
FirstEnergy Money Pools
FirstEnergy'sFirstEnergy’s regulated companies, excluding regulated companies acquired in the Allegheny merger, 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'sFirstEnergy’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 the first three monthsquarter of 20102011 was 0.4 9%0.38% per annum for the regulated companies'companies’ money pool and 0.54%0.47% per annum for the unregulated companies'companies’ money pool. In March 2011, AE Supply invested $200 million into the unregulated money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to be part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of March 31, 2010, FirstEnergy's2011, FirstEnergy’s currently payable long-term debt included approximately $1.6 billion$827 million (FES - $1.5 billion,— $778 million, Met-Ed -— $29 million and Penelec - $45— $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 March 31, 2010:2011:
| | | | | | | | | |
| | | Aggregate LOC | | | | | Reimbursements of |
| LOC Bank | | Amount(1) | | | LOC Termination Date | | LOC Draws Due |
| | | (In millions) | | | | | |
| CitiBank N.A. | | $ | 166 | | | June 2014 | | June 2014 |
| The Bank of Nova Scotia | | | 178 | | | Beginning June 2012 | | Multiple dates(2) |
| The Royal Bank of Scotland | | | 131 | | | June 2012 | | 6 months |
| Wachovia Bank | | | 152 | | | March 2014 | | March 2014 |
| US Bank | | | 60 | | | April 2014 | | 6 months |
| UBS | | | 272 | | | April 2014 | | April 2014 |
| | | | | | | | |
| Total | | $ | 959 | | | | | |
| | | | | | | | |
| | | Aggregate LOC | | | | Reimbursements of |
| LOC Bank | | Amount(3) | | LOC Termination Date | | LOC Draws Due |
| | | (In millions) | | | | |
| CitiBank N.A. | | $ | 166 | | June 2014 | | June 2014 |
| The Bank of Nova Scotia | | 284 | | Beginning April 2011 | | Multiple dates(4) |
| The Royal Bank of Scotland | | 131 | | June 2012 | | 6 months |
KeyBank(1) | | 237 | | June 2010 | | 6 months |
| Wachovia Bank | | 153 | | March 2014 | | March 2014 |
Barclays Bank(2) | | 528 | | Beginning December 2010 | | 30 days |
| PNC Bank | | 70 | | Beginning November 2010 | | 180 days |
| Total | | $ | 1,569 | | | | |
| | | | | | | | |
(1) Supported by four participating banks, with the LOC bank having 58% of the total commitment. (2) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3) Includes approximately $16 million of applicable interest coverage. (4) Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million). |
| | |
| (1) | | Includes approximately $10 million of applicable interest coverage. |
|
| (2) | | Shorter of 6 months or LOC termination date ($49 million) and shorter of one year or LOC termination date ($129 million). |
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In April 2010, FGCO purchased approximately $235On March 17, 2011, FES completed the remarketing of $207 million variable rate PCRBs. These PCRBs remained in a variable interest mode, supported by bank LOC’s. Also, on March 1, 2011, FES repurchased $50 million of non-LOC backed fixed rate PCRBs that were subject to purchase on demand by the owner on that date.
On April 1, 2011, FES completed the remarketing of an additional $97 million of non-LOC backed commercial paper rate and cancelled its $237fixed rate PCRBs (including the $50 million repurchased on March 1) into variable rate modes with LOC with KeyBank as shown above. FGCO plans to remarket these securitiessupport. Also on April 1, 2011, Penelec completed the remarketing of $25 million of non-LOC backed commercial paper rate PCRBs into a fixedvariable rate mode during 2010.with LOC support.
In connection with the remarketings, approximately $207 aggregate principal amount of FMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of FMBs delivered to secure PCRBs will be cancelled on May 31, 2011.
Long-Term Debt Capacity
As of March 31, 2010,2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.3$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 $101$118 million and $17 mill ion, respectively, as of March 31, 2010.million, respectively. As a result of theits indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $379$365 million and $345$346 million, respectively, under provisions of their senior note indentures as of March 31, 2010.
2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of March 31, 2011, MP, PE and WP had the capability to issue approximately $685 million of additional FMBs in the aggregate.
Based upon FGCO'sFGCO’s FMB indenture, net earnings and available bondable property additions as of March 31, 2010,2011, FGCO had the capability to issue $2.4 billion of additional FMBs under the terms of that indenture. In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $294 million$1.2 billion of additional FMBs as of March 31, 2010.
FirstEnergy'sFirstEnergy’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’sMarch 1, 2011, Fitch affirmed the ratings and outlook of FirstEnergy and its subsidiaries credit ratings by one notch, while maintaining its stable outlook.subsidiaries. On February 25, 2011, Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries on February 11, 2010.regulated utilities, upgraded AE’s senior unsecured ratings to Baa3 from Ba1 and placed the ratings for FES under review for possible downgrade. The following table displays FirstEnergy's, FES'FirstEnergy’s and the Utilities'its subsidiaries’ securities ratings as of March 31, 2010.
2011.
Issuer
| Senior Secured
| Senior Unsecured |
S&P | Moodys | Fitch | S&P | Moodys | Fitch |
FirstEnergy Corp. | - | - | - | BB+ | Baa3 | BBB |
| | | | | | | |
| | Senior Secured | | Senior Unsecured |
| Issuer | | S&P | | Moody’s | | Fitch | | S&P | | Moody’s | | Fitch |
FirstEnergy SolutionsCorp. | - | -— | - | BBB-— | Baa2 | — | | BB+ | | Baa3 | | BBB |
| Allegheny | | — | | — | | — | | BB+ | | Baa3 | | BBB- |
Ohio EdisonFES | BBB | A3— | BBB+ | — | | — | | BBB- | | Baa2 | | BBB |
| AE Supply | | BBB | | Baa2 | | |
Pennsylvania Power | BBB+ | A3 | BBB+ | - | - | - |
| BBB | | BBB- | | Baa3 | | |
Cleveland Electric Illuminating | BBB | Baa1 | BBB | BBB- | Baa3 | BBB- |
| AGC | | — | | — | | — | | BBB- | | Baa3 | | BBB- |
Toledo EdisonATSI | | — | | — | | — | | BBB- | | Baa1 | | — |
| CEI | | BBB | | Baa1 | | BBB | - | - | - |
| BBB- | | Baa3 | | BBB- |
| JCP&L | | |
Jersey Central Power & Light— | - | -— | - | — | | BBB- | | Baa2 | | BBB+ |
| Met-Ed | | BBB | | A3 | | |
Metropolitan EdisonBBB+ | BBB | A3 | BBB+ | BBB- | | Baa2 | | BBB |
| MP | | BBB+ | | Baa1 | | BBB+ | | BBB- | | Baa3 | | BBB- |
Pennsylvania ElectricOE | | BBB | | A3 | | BBB+ | | BBB- | | Baa2 | | BBB |
| Penelec | | BBB | | A3 | | |
ATSIBBB+ | - | - | - | BBB- | | Baa2 | | BBB |
| Penn | | BBB+ | | A3 | | BBB+ | | — | | — | | — |
| PE | | BBB+ | | Baa1 | - | BBB+ | | BBB- | | Baa3 | | BBB- |
| TE | | BBB | | Baa1 | | BBB | | — | | — | | — |
| TrAIL | | — | | — | | — | | BBB- | | Baa2 | | BBB |
| WP | | BBB+ | | A3 | | BBB+ | | BBB- | | Baa2 | | BBB- |
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Changes in Cash Position
As of March 31, 2010,2011, FirstEnergy had $310 million in$1.1 billion of cash and cash equivalents compared to $874 million$1 billion as of December 31, 2009.2010. As of March 31, 20102011 and December 31, 2009,2010, FirstEnergy had approximately $12$73 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first three months of 2010,2011, FirstEnergy received $620$240 million of cash dividends from its subsidiaries and paid $168$190 million in cash dividends to common shareholders, including $20 million paid in March by Allegheny to its former shareholders.
Cash Flows From Operating Activities
FirstEnergy'sFirstEnergy’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 increaseddecreased by $44$15 million during the first three months of 20102011 compared to the comparable period in 2009,2010, as summarized in the following table:
| | | | | | | | | | | | | | |
| | | | Three Months | | | |
| | | Three Months Ended March 31 | | | | | | Ended March 31 | | Increase | |
Operating Cash Flows | | 2010 | | 2009 | | Increase (Decrease) | | | 2011 | | 2010 | | (Decrease) | |
| | | (In millions) | | | (In millions) | |
| Net income | | $ | 149 | | $ | 115 | | $ | 34 | | | $ | 45 | | $ | 149 | | $ | (104 | ) |
| Non-cash charges and other adjustments | | | 367 | | | 375 | | | (8 | ) | | 515 | | 367 | | 148 | |
| Pension trust contribution | | | | (157 | ) | | — | | | (157 | ) |
| Working capital and other | | | (10 | ) | | (28 | ) | | 18 | | | 88 | | | (10 | ) | | 98 | |
| | | $ | 506 | | $ | 462 | | $ | 44 | | | | | | | | |
| | | | $ | 491 | | $ | 506 | | $ | (15 | ) |
| | | | | | | | | |
The decreaseincrease in non-cash charges and other adjustments is primarily due to lower net amortization of regulatory assets ($106 million), including CEI’s $216 million regulatory asset impairment recorded in the first quarter of 2009, partially offset by higher netincreased deferred income taxes and investment tax credits ($87112 million), increased asset impairments ($19 million), changes in accrued compensation and retirement benefits ($68 million) and anincreased depreciation ($27 million), partially offset by lower amortization of regulatory assets ($80 million).
The increase in the provision for depreciation ($16 million). The changes incash flows from working capital and other is primarily resulted from a $104 million decrease indue to decreased receivables ($162 million), decreased prepayments and other current assets ($85 million) and an $58 million increase in accrued taxes,decreased materials and supplies ($82 million), partially offset by a $52 million decrease in accrued interest, a $44 million increase in receivables and a $31 million increase in cash collateral paid. The change indecreased accrued taxes ($189 million) and prepayments primarily relates to the timing of income ta x payments. The decrease in accrued interest primarily relates to the $1.2 billion tender offer of holding company notes in the third quarter of 2009 combined with the timing of payments relating to new debt issuances in 2009.
decreased accounts payable ($33 million).
Cash Flows From Financing Activities
In the first three months of 2010,2011, cash used for financing activities was $594$550 million compared to cash provided from financing activities of $70$594 million in the first three months of 2009. The decrease was primarily due to new debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased long-term debt redemptions in 2010. The following table summarizes security issuances (net of any discounts) and redemptions.redemptions:
| | | | | | | | | |
| | | Three Months | |
| | | Ended March 31 | |
| Securities Issued or Redeemed | | 2011 | | | 2010 | |
| | | (In millions) | |
New Issues | | | | | | | | |
| Pollution control notes | | | 150 | | | | — | |
| Long-term revolvers | | | 60 | | | | — | |
| Unsecured Notes | | | 7 | | | | — | |
| | | | | | | |
| | | $ | 217 | | | $ | — | |
| | | | | | | |
| | | | | | | | | |
Redemptions | | | | | | | | |
| Pollution control notes | | | (200 | ) | | | — | |
| Long-term revolvers | | | (20 | ) | | | — | |
| Senior secured notes | | | (109 | ) | | | 9 | |
| Unsecured notes | | | (30 | ) | | | 100 | |
| | | | | | | |
| | | $ | (359 | ) | | $ | 109 | |
| | | | | | | |
| | | | | | | | | |
| Short-term borrowings, net | | $ | (214 | ) | | $ | (295 | ) |
| | | | | | | |
| | | Three Months Ended | |
| | | March 31 | |
Securities Issued or Redeemed | | 2010 | | 2009 | |
| | | (In millions) | |
| New issues | | | | | | | |
| Pollution control notes | | $ | - | | $ | 100 | |
| Unsecured notes | | | - | | | 600 | |
| | | $ | - | | $ | 700 | |
| | | | | | | | |
| Redemptions | | | | | | | |
| Pollution control notes | | $ | - | | $ | 437 | |
| Senior secured notes | | | 9 | | | 7 | |
| Met-Ed unsecured notes | | | 100 | | | - | |
| | | $ | 109 | | $ | 444 | |
| | | | | | | | |
| Short-term borrowings, net | | $ | (295 | ) | $ | - | |
In March 2011 FES repurchased and retired $20 million of its 6.80% unsecured senior notes and $10 million of its 6.05% unsecured senior notes originally outstanding in the principal amounts of $500 million and $600 million, respectively. Additionally, on April 29, 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.
During the remainder of 2011, FirstEnergy and its subsidiaries expect to pursue, from time to time, continued reductions in outstanding long-term debt of up to approximately $1.0 to $1.5 billion including through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements and other factors.
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Cash Flows From Investing Activities
Net cashCash flows used inreceived from investing activities in the first three months of 2011 resulted primarily from the cash acquired in the Allegheny merger, partially offset by cash used for 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 the first three months ended March 31,of 2011 and 2010 and 2009 by business segment:
| | | | | | | | | | | | | | | | | | |
| Summary of Cash Flows | | Property | | | | | | | | | Property | | | | | | | |
| Provided from (Used for) Investing Activities | | Additions | | Investments | | Other | | Total | | | Additions | | Investments | | Other | | Total | |
| | | | (In millions) | |
| Sources (Uses) | | (In millions) | | |
| Three Months Ended March 31, 2010 | | | | | | | | | | |
| | | (166 | | | 62 | | | (7 | | | (111 | | |
Three Months Ended March 31, 2011 | | |
| Regulated distribution | | | $ | (177 | ) | | $ | 60 | | $ | (9 | ) | | $ | (126 | ) |
Competitive energy services | | (323 | | | - | | (1 | | | (324 | | | | (214 | ) | | | (15 | ) | | | (8 | ) | | | (237 | ) |
| Regulated independent transmission | | | | (27 | ) | | | (1 | ) | | — | | | (28 | ) |
| | (3 | | | - | | - | | | (3 | | | | (31 | ) | | 590 | | 145 | | 704 | |
Inter-Segment reconciling items | | | (16 | | | (22 | | | - | | | (38 | | | — | | | (22 | ) | | | (150 | ) | | | (172 | ) |
| | | | | | | | | | | |
| | | (508 | | | 40 | | | (8 | | | (476 | | | $ | (449 | ) | | $ | 612 | | $ | (22 | ) | | $ | 141 | |
| | | | | | | | | | | | | | | | | | | | |
Three Months Ended March 31, 2009 | | | | | | | | | | | |
| | $ | (165 | ) | $ | 51 | | $ | (14 | ) | $ | (128 | ) | |
| | | |
Three Months Ended March 31, 2010 | | |
| Regulated distribution | | | $ | (152 | ) | | $ | 62 | | $ | (6 | ) | | $ | (96 | ) |
Competitive energy services | | (421 | ) | | 2 | | (19 | ) | | (438 | ) | | | (329 | ) | | — | | | (1 | ) | | | (330 | ) |
| Regulated independent transmission | | | | (14 | ) | | — | | | (1 | ) | | | (15 | ) |
| | (49 | ) | | (20 | ) | | 1 | | | (68 | ) | | | (13 | ) | | — | | — | | | (13 | ) |
Inter-Segment reconciling items | | | (19 | ) | | (25 | ) | | - | | | (44 | ) | | — | | | (22 | ) | | — | | | (22 | ) |
| | | | | | | | | | | |
| | $ | (654 | ) | $ | 8 | | $ | (32 | ) | $ | (678 | ) | | $ | (508 | ) | | $ | 40 | | $ | (8 | ) | | $ | (476 | ) |
| | | | | | | | | | | |
Net cash used forprovided from investing activities in the first three months of 2010 decreased2011 increased by $202$617 million compared to the first three months of 2009.2010. The decreaseincrease was principally due to cash acquired in the Allegheny merger ($590 million), a $146 milliondecrease in purchases of customer intangibles by FES in the customer acquisition process ($100 million) and a decrease in property additions which reflects($59 million), principally due to lower AQC system expenditures, and cash proceeds of approximately $114 million from the sale of assets, partially offset by $101 million relating to the acquisition of customer intangible assets.decreased proceeds from asset sales ($114 million).
During the remaining three quartersnine months of 2010,2011, capital requirements for property additions and capital leases are expected to be approximately $1.1$1.8 billion. TheseThis includes approximately $90 million of nuclear fuel expenditures.
CONTRACTUAL OBLIGATIONS
Estimated cash requirementspayments for contractual obligations that are expected to be satisfied from a combination of internal cash and short-term credit arrangements.considered firm obligations acquired by FirstEnergy in the AE merger are summarized as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | 2012- | | | 2014- | | | | |
| Contractual Obligations | | Total | | | 2011 | | | 2013 | | | 2015 | | | Thereafter | |
| | | (In millions) | |
Long-term debt(1) | | $ | 4,776 | | | $ | 8 | | | $ | 1,445 | | | $ | 1,037 | | | $ | 2,286 | |
Interest on long-term debt(2) | | | 2,516 | | | | 240 | | | | 470 | | | | 341 | | | | 1,465 | |
Fuel and purchased power(3) | | | 9,781 | | | | 956 | | | | 2,160 | | | | 1,650 | | | | 5,015 | |
| Capital expenditures | | | 141 | | | | 117 | | | | 24 | | | | — | | | | — | |
Pension funding (4) | | | 695 | | | | 124 | | | | 175 | | | | 186 | | | | 210 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 17,909 | | | $ | 1,445 | | | $ | 4,274 | | | $ | 3,214 | | | $ | 8,976 | |
| | | | | | | | | | | | | | | | |
| | |
| (1) | | Does not include payments made and debt issued subsequent to March 31, 2011. |
|
| (2) | | Interest on variable-rate debt is based on interest rates as of March 31, 2011. |
|
| (3) | | Amounts under contract with fixed or minimum quantities are based on estimated annual requirements. |
|
| (4) | | Estimated contributions through 2021 based on current actuarial assumptions. |
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.
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As of March 31, 2010,2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.0$3.8 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) | | $ | 231 | |
| FirstEnergy guarantee of OVEC obligations | | | 300 | |
Other(2) | | | 228 | |
| | | | |
| | | | 759 | |
| | | | |
| | | | | |
| Subsidiaries’ Guarantees | | | | |
| Energy and Energy-Related Contracts | | | 158 | |
| FES’ guarantee of NGC’s nuclear property insurance | | | 70 | |
| FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,375 | |
| Other | | | 18 | |
| | | | |
| | | | 2,621 | |
| | | | |
| | | | | |
| Surety Bonds | | | 138 | |
LOC (non-debt)(3) | | | 318 | |
| | | | |
| | | | 456 | |
| | | | |
| Total Guarantees and Other Assurances | | $ | 3,836 | |
| | | | |
| | | Maximum | |
Guarantees and Other Assurances | | | |
| | | (In millions) | |
| FirstEnergy Guarantees on Behalf of its Subsidiaries | | | |
Energy and Energy-Related Contracts (1) | | $ | 324 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
| FirstEnergy guarantee of OVEC obligations | | | 300 | |
Other (3) | | | 297 | |
| | | | 927 | |
| | | | | |
| Subsidiaries’ Guarantees | | | | |
| Energy and Energy-Related Contracts | | | 54 | |
LOC (long-term debt) – interest coverage (2) | | | 6 | |
| FES’ guarantee of NGC’s nuclear property insurance | | | 77 | |
| FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,464 | |
| | | | 2,601 | |
| | | | | |
| Surety Bonds | | | 77 | |
LOC (long-term debt) – interest coverage (2) | | | 3 | |
LOC (non-debt) (4)(5) | | | 423 | |
| | | | 503 | |
| Total Guarantees and Other Assurances | | $ | 4,031 | |
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
$1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s
consolidated balance sheets.
(3) Includes guarantees of $80 million for nuclear decommissioning funding assurances and $161 million supporting OE’s sale and leaseback arrangement.
(4) Includes $231 million issued for various terms pursuant to LOC capacity availableunder FirstEnergy’s revolving credit facility.
(5) Includes approximately $145 million pledged in connection with the sale andleaseback of Beaver Valley Unit 2 by OE and $47 million pledged in connection with
the sale and leaseback of Perry by OE.
| | |
| (1) | | Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
|
| (2) | | Includes guarantees of $15 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $37 million for railcar leases. |
|
| (3) | | Includes $146 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $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'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'scounterparty’s legal claim to be satisf iedsatisfied 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.
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 a LOC or accelerated payments may be required of the subsidiary. 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 was required to post $46 million of collateral. Moody’s and Fitch affirmed the ratings and stable outlook of FirstEnergy and its subsidiaries. As of March 31, 2010,2011, FirstEnergy’s maximum exposure under these collateral provisions was $428$557 million, as shown below:
| | | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | | AE Supply | | | Utilities | | | Total | |
| | | (In millions) | |
Credit rating downgrade to below investment grade(1) | | $ | 357 | | | $ | 10 | | | $ | 66 | | | $ | 433 | |
Material adverse event(2) | | | 54 | | | | 57 | | | | 13 | | | | 124 | |
| | | | | | | | | | | | | |
| Total | | $ | 411 | | | $ | 67 | | | $ | 79 | | | $ | 557 | |
| | | | | | | | | | | | | |
| Collateral Provisions | | FES | | Utilities | | Total | |
| | | (In millions) | |
| Credit rating downgrade to below investment grade | | $ | 318 | | $ | 10 | | $ | 328 | |
| Acceleration of payment or funding obligation | | | 15 | | | 48 | | | 63 | |
| Material adverse event | | | 37 | | | - | | | 37 | |
| Total | | $ | 370 | | $ | 58 | | $ | 428 | |
| | |
| (1) | | Includes $138 million and $46 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively. |
|
| (2) | | Includes $53 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 $656$623 million, consisting of $38 million due to “material adverse event” contractual clauses, $63 million due to an acceleration of payment or funding obligation, and $555 million due to a below investment grade credit rating.as shown below:
| | | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | | AE Supply | | | Utilities | | | Total | |
| | | (In millions) | |
Credit rating downgrade to below investment grade(1) | | $ | 420 | | | $ | 8 | | | $ | 66 | | | $ | 494 | |
Material adverse event(2) | | | 60 | | | | 56 | | | | 13 | | | | 129 | |
| | | | | | | | | | | | | |
| Total | | $ | 480 | | | $ | 64 | | | $ | 79 | | | $ | 623 | |
| | | | | | | | | | | | | |
| | |
| (1) | | Includes $138 million and $46 million that is also considered an acceleration of payment or funding obligation at FES and the Utilities, respectively. |
|
| (2) | | Includes $53 million that is also considered an acceleration of payment or funding obligation at FES. |
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $77$138 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 entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions whichthat require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolio as of March 31, 2010,2011 and forward prices as of that date, FES hasand AE Supply have posted collateral of $270 million.$158 million and $5 million, respectively. 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 $168 million.$52 million of collateral. Depending on the volume of forward contracts entered and future price movements, FEShigher amounts for margining could be required to post higher amounts for margining.
be posted.
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, pursuant toand FES guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC willmay have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, 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 lenders under the term loan facility 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, is $1.7 billion as of March 31, 2010.2011.
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'sFirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
FirstEnergy is exposed to financial and market risks resulting from the fluctuation offluctuating interest rates and commodity prices, associated withincluding prices for electricity, energy transmission, natural gas, coal nuclear fuel and emission allowances.energy transmission. To manage the volatility relating to these exposures, FirstEnergy established a Risk Policy Committee, comprised of members of senior management, which 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 practice. FirstEnergy uses a variety of non-derivative and derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. TheIn addition to derivatives, are used principally for hedging purposes. Certain derivatives must be recorded at their fair value and marked to market. The majority of FirstEnergy's derivative hedging contracts qualify for the normal purchase and normal sale exception and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchaseFirstEnergy also enters into master netting agreements with NUG entities that were structure d pursuant to the Public Utility Regulatory Policies Act of 1978 and certain purchase power contracts (Note 4). The NUG entities non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The following table sets forth the change in the fair value of commodity derivative contracts related to energy production as of March 31, 2010:third parties.
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| Increase (Decrease) in the Fair Value of Derivative Contracts | | Non-Hedge | | Hedge | | Total | |
| | | (In millions) | |
| Change in the Fair Value of Commodity Derivative Contracts: | | | | | | | |
Outstanding net liability as of January 1, 2010 | | | (630 | ) | | (15 | ) | | (645 | ) |
Additions/change in value of existing contracts | | | (276 | | | (6 | | | (282 | |
| | | 94 | | | 7 | | | 101 | |
Outstanding net liability as of March 31, 2010(1) | | $ | (812 | ) | $ | (14 | ) | $ | (826 | ) |
| | | | | | | | | | | |
Non-Commodity Net Liabilities as of March 31, 2010: | | | | | | | | | | |
| | | - | | | (2 | ) | | (2 | ) |
| | | | | | | | | | | |
Net Liabilities-Derivative Contracts as of March 31, 2010 | | | (812 | | | (16 | | | (828 | |
| | | | | | | | | | | |
Impact of Changes in Commodity Derivative Contracts(2) | | | | | | | | | | |
Income Statement effects (pre-tax) | | | (27 | | | - | | | (27 | |
| | | | | | | | | | |
| | | - | | | 1 | | | 1 | |
| | | 155 | | | - | | | 155 | |
| | | | | | | | | | | |
(1) Includes $580 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. (2) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions. |
Derivatives are included on the Consolidated Balance Sheet as of March 31, 2010 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | |
| | | (In millions) | |
| | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | |
| | | | | | | | | | | |
| | | | | | | | | | |
| | | 158 | | | 22 | | | 180 | |
Other non-current liabilities | | | (831 | ) | | (30 | ) | | (861 | ) |
| | | (812 | ) | | (16 | ) | | (828 | ) |
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 36 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31, 20102011 are summarized by 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) | | | (315 | ) | | | (152 | ) | | | (44 | ) | | | (36 | ) | | | — | | | | — | | | | (547 | ) |
| Prices based on models | | | (11 | ) | | | — | | | | — | | | | — | | | | 19 | | | | 106 | | | | 114 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total(3) | | $ | (326 | ) | | $ | (152 | ) | | $ | (44 | ) | | $ | (36 | ) | | $ | 19 | | | $ | 106 | | | $ | (433 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
| Source of Information | | | | | | | | | | | | | | | |
- Fair Value by Contract Year | | | | | | | | | | | | | | | |
| | | (In millions) | |
Prices actively quoted(1) | | $ | (8 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | - | | $ | (8 | ) |
Other external sources(2) | | | (409 | ) | | (374 | ) | | (166 | ) | | (59 | ) | | - | | | - | | | (1,008 | ) |
| Prices based on models | | | | | | | | | | | | | | | | ) | | | | | | |
Total(3) | | | | ) | | | ) | | | ) | | | ) | | | ) | | | | | | ) |
(1) Represents exchange traded NYMEX futures and options.
(2) Primarily represents contracts based on broker and ICE quotes.
(3) Includes $580 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.
| | |
| (1) | | Represents exchange traded New York Mercantile Exchange futures and options. |
|
| (2) | | Primarily represents contracts based on broker and IntercontinentalExchange quotes. |
|
| (3) | | Includes $366 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings. |
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2010. Based on derivative contracts held as of March 31, 2010,2011, an adverse 10% change in commodity prices would decrease net income by approximately $4$12 million ($7 million net of tax) during the next 12 months.
Interest Rate Swap Agreements – Fair Value Hedges
FirstEnergy uses 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 are 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. Swap maturities, call options, fixed interest rates and interest payment dates match those of the underlying obligations. As of March 31, 2010, the debt underlying the $950 million outstanding notional amount of interest rate swaps had a weighted average fixed interest rate of 5.5%, which the swaps have converted to a current weighted average variable rate of 3.74%. The fair value of the interest rate swaps designated as fair value hedges was immaterial as o f March 31, 2010.
On April 29, 2010, April 30, 2010 and May 3, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with combined notional amounts of $1.3 billion, $300 million and $600 million, respectively, to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. This is consistent with FirstEnergy’s risk management policy and its 2010 financial plan. These derivatives will be 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 May 3, 2010, the debt underlying the $2.2 billion outstanding notional amount of interest rate swaps had a weighted average fixed intere st rate of 6%, which the swaps have converted to a current weighted average variable rate of 3.4%.
Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with 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. During the first three months of 2010, FirstEnergy terminated forward swaps with a notional value of $100 million. The termination of the forward starting swap agreements did not materially impact FirstEnergy’s net income and no forward starting swap agreements were outstanding as of March 31, 2010.
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees other than Allegheny employees employed by FirstEnergy and non-qualified pension plans that cover certain employees.employees (the FirstEnergy Pension Plan). In addition, effective on the date of the merger, FirstEnergy provides noncontributory qualified defined pension plan benefits that cover substantially all of Allegheny employees employed by FirstEnergy and a supplemental executive retirement plan that covers certain Allegheny executives employed by FirstEnergy (the Allegheny Pension Plan). The plan providesFirstEnergy Pension Plan and the Allegheny Pension Plan provide defined benefits based on years of service and compensation levels.
Eligible 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,retirees, their dependents and, under certain circumstances, their survivors. survivors are provided other postretirement benefits such as a minimum amount of noncontributory life insurance, optional contributory insurance and certain health care benefits. These other postretirement benefits are not provided in retirement for employees hired on or after January 1, 2005.
Eligible Allegheny retirees and dependents are provided other postretirement benefits such as subsidies for medical and life insurance plans. Subsidized medical coverage is not provided in retirement to Allegheny employees employed by FirstEnergy that were hired on or after January 1, 1993, with the exception of certain union employees who were hired or became members before May 1, 2006.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of DecemberMarch 31, 2009,2011, the FirstEnergy pension plan was underfunded.invested in approximately 32% of equity securities, 47% of fixed income securities, 10% of absolute return strategies, 5% of real estate, 2% of private equity and 4% of cash. The FirstEnergy currently estimates thatPension Plan and the Allegheny Pension Plan were 86% and 78%, respectively, funded on an accumulated benefit obligation basis as of March 31, 2011. A decline in the value of pension plan assets could result in additional cash contributions will be required beginning in 2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return. Basedfunding requirements. FirstEnergy’s funding policy is based on a 6% discount rate, FirstEnergy’s pre-tax net periodic pension and OPEB expense was $24 million inactuarial computations using the projected unit credit method. During the first quarter of 2010.2011, FirstEnergy made a $157 million contribution to its qualified pension plans. FirstEnergy intends to make additional contributions of $220 million and $6 million to its qualified pension plans and postretirement benefit plans, respectively, in the last three quarters of 2011.
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Nuclear decommissioning trust funds have been established to satisfy NGC'sNGC’s and the Utilities'Utilities’ nuclear decommissioning obligations. As of March 31, 2010,2011, approximately 17%85% of the funds were invested in fixed income securities, 9% of the funds were invested in equity securities and 83%6% were invested in fixed income securities,short-term investments, with limitations related to concentration and investment grade ratings. The equity securitiesinvestments are carried at their market valuevalues of approximately $311$1,741 million, $194 million and $115 million for fixed income securities, equity securities and short-term investments, respectively, as of MarchMach 31, 2010.2011, excluding $(31) million of receivables, payables, deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $31$19 million reduction in fair value as of March 31, 2010.2011. 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. FirstEnergy continues to evaluateA decline in the statusvalue of its funding obligations for the decommissioning of these nuclear facilities and does not expect to make additional cash contributions to theFirstEnergy’s nuclear decommissioning trusts or a significant escalation in 2010 other thanestimated decommissioning costs could result in additional funding requirements. In the required annual trust contributions.first three months of 2011, approximately $1 million was contributed to JCP&L’s nuclear decommissioning trusts. During the second quarter of 2011, FirstEnergy intends to contribute approximately $4 million and $1 million to the OE and TE nuclear decommissioning trusts, respectively, to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $93 million. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.
CREDIT RISK
Credit risk is the risk of an obligor'sobligor’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 March 31, 2010,2011, the largest credit concentration was with J. AronJ.P. Morgan Chase & Company,Co., which is currently rated investment grade, representing 7.4%13.4% of FirstEnergy’s total approved credit risk.
OUTLOOK
As a resultrisk comprised of economic conditions and the milder weather experienced in the first quarter of 2010, 2010 distribution sales are expected to be approximately 106 million MWH in 2010, while generation output5.9% for 2010 is expected to be 77.1 million MWH.
State Regulatory Matters
Regulatory assets that do not earn a current return totaled approximately $213 million as of March 31, 2010 (JCP&L - $46 million, Met-Ed - $122 million, and Penelec - $47 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014FES, 2.1% for JCP&L, and by 20202.7% for Met-Ed and Penelec. The following table discloses regulatory assets by company:a combined 2.7% for OE, TE and CEI.
OUTLOOK
| | | March 31, | | December 31, | | Increase | |
| Regulatory Assets | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| OE | | $ | 432 | | $ | 465 | | $ | (33 | ) |
| CEI | | | 498 | | | 546 | | | (48 | ) |
| TE | | | 82 | | | 70 | | | 12 | |
| JCP&L | | | 856 | | | 888 | | | (32 | ) |
| Met-Ed | | | 393 | | | 357 | | | 36 | |
| Penelec | | | 119 | | | 9 | | | 110 | |
| Other | | | | | | | | | | ) |
| Total | | | | | | | | | | |
Regulatory assets by source are as follows:
| | | March 31, | | December 31, | | Increase | |
| Regulatory Assets By Source | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| Regulatory transition costs | | $ | 1,219 | | $ | 1,100 | | $ | 119 | |
| Customer shopping incentives | | | 113 | | | 154 | | | (41 | ) |
| Customer receivables for future income taxes | | | 335 | | | 329 | | | 6 | |
| Loss on reacquired debt | | | 50 | | | 51 | | | (1 | ) |
| Employee postretirement benefits | | | 21 | | | 23 | | | (2 | ) |
| Nuclear decommissioning, decontamination | | | | | | | | | | |
| and spent fuel disposal costs | | | (174 | ) | | (162 | ) | | (12 | ) |
| Asset removal costs | | | (235 | ) | | (231 | ) | | (4 | ) |
| MISO/PJM transmission costs | | | 157 | | | 148 | | | 9 | |
| Fuel costs | | | 377 | | | 369 | | | 8 | |
| Distribution costs | | | 431 | | | 482 | | | (51 | ) |
| Other | | | | | | | | | | |
| Total | | | | | | | | | | |
Reliability Initiatives
In 2005, Congress amended the FPA to provide for federally-enforceable mandatory reliability standards. TheFederally-enforceable mandatory reliability standards apply to the bulk powerelectric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, and ATSI.ATSI and TrAIL Company. 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 responsibilitiesthese 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.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, thetime; 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.
In April 2007, ReliabilityFirst performed 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, ReliabilityFirst performed 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. FirstEnergy’s MISO facilities are next due for the periodic audit by ReliabilityFirst later this year.
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 withresulting in customers in the affected area losing power. Power was restoredpower for up to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. 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. The initial phase of the investigation requiredNERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviewsis complying with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009.these requests. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.with respect to this matter.
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On June 5, 2009,August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta potentialvegetation 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. In March 2011, ReliabilityFirstsubmitted its proposed findings and settlement. At this time, FirstEnergy is evaluating ReliabilityFirst’s proposal and is unable to predict the final outcome of this investigation.
Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain violation investigations with regard to matters of NERC Standard PRC-005 resultingcompliance by Allegheny.
Maryland
In 1999, Maryland adopted electric industry restructuring legislation, which gave PE’s Maryland retail electric customers the right to choose their electricity generation suppliers. PE remained obligated to provide standard offer generation service (SOS) at capped rates to residential and non-residential customers for various periods. The longest such period, for residential customers, expired on December 31, 2008. PE implemented a rate stabilization plan in 2007 that was designed to transition customers from its inabilitycapped generation rates to validate maintenance recordsrates based on market prices and that concluded on December 31, 2010. PE’s transmission and distribution rates for 20 protection system relays (outall customers are subject to traditional regulated utility ratemaking (i.e., cost-based rates).
By statute enacted in 2007, the obligation of approximately 20,000 reportable relays)Maryland utilities to provide SOS to residential and small commercial customers, in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered duringexchange for recovery of their costs plus a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance recordsreasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the relays. ReliabilityFirstMDPSC to report to the legislature on the status of SOS. In August 2007, PE filed a plan for seeking bids to serve its Maryland residential load for the period after the expiration of rate caps. The MDPSC approved the plan and PE now conducts rolling auctions to procure the power supply necessary to serve its customer load. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.
The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.
In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an Initial Noticeorder soliciting comments on a model request for proposal for solicitation of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 200 9,long-term energy commitments by Maryland electric utilities. PE and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not ablenumerous other parties filed comments, and at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose forno further proceedings have been set by the MDPSC in this self-reported violation.matter.
Ohio
On June 7,In September 2007, the Ohio Companies filedMDPSC issued an application for an increase in electric distribution rates withorder that required the PUCO and, on August 6, 2007, updated their filing. On January 21, 2009, the PUCO granted the Ohio Companies’ application in part to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electricMaryland utilities to file an ESP,detailed plans for how they will meet the “EmPOWER Maryland” proposal that, in Maryland, electric consumption be reduced by 10% and permittedelectricity demand be reduced by 15%, in each case by 2015. In October 2007, PE filed its initial report on energy efficiency, conservation and demand reduction plans in connection with this order. The MDPSC conducted hearings on PE’s and other utilities’ plans in November 2007 and May 2008.
In a related development, the filing of an MRO. On July 31,Maryland legislature in 2008 adopted a statute codifying the Ohio CompaniesEmPOWER Maryland goals. In 2008, PE filed withits comprehensive plans for attempting to achieve those goals, asking the PUCOMDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a comprehensive ESPcustomer education program, and a separate MRO.pilot deployment of Advanced Utility Infrastructure (AUI) that Allegheny had previously tested in West Virginia. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The PUCO has not yet issued a substantive Entry on Rehearing. The ESP proposed by the Ohio Companies was approved by the PUCO on December 19, 2008. The Ohio Companies thereafter withdrew and terminated the ESP and continued their rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCOMDPSC ultimately approved the Ohio Companies’ request for a new fuel rider, which recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.
On February 19,programs in August 2009 the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signedafter certain modifications had been made as required by the Ohio Companies,MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. The AUI pilot was placed on a separate track to be re-examined after further discussion with the Staff of the PUCO,MDPSC and manyother stakeholders. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011.
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In March 2009, the Maryland PSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. PE and several other utilities filed requests for reconsideration of various parts of the intervening parties. Specifically,order, which were denied. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the Amended ESP provided that generation would besummer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by FES atstatute, to three days on each occurrence.
On March 24, 2011, the average wholesale rateMDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. Concurrently, the Maryland legislature is considering a bill addressing the same topics. The final bill passed on April 11, 2011, requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the MDPSC is directed to consider cost-effectiveness, and may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the CBP described aboveproposed rules.
In December 2009, PE filed an application with the MDPSC for Aprilauthorization to construct the Maryland portions of the PATH Project to be owned by PATH Allegheny Maryland Transmission Company, LLC, which is owned by Potomac Edison and PATH-Allegheny. On February 28, 2011, PE withdrew its application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
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 NUG rates and market sales of NUG energy and capacity. As of March 31, 2011, the accumulated deferred cost balance was a credit of approximately $102 million. To better align the recovery of expected costs, in July 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually, which the NJBPU approved, allowing the change in rates to become effective March 1, 2011.
In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero 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). Both matters are currently pending before the NJBPU.
Ohio
The Ohio Companies operate under an ESP, which expires on May 2009 to31, 2011, that provides for generation supplied through a CBP. The ESP also allows the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to w rite-off approximately $216 million of its Extended RTC regulatory asset, and that the Ohio Companies would collect a delivery service improvement rider (Rider DSI) at an overall average rate of $.002$0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressedOhio Companies currently purchase generation at the average wholesale rate of a number of other issues, including but not limited to, rate design for various customer classes, and resolutionCBP conducted in May 2009. FES is one of the prudence reviewsuppliers 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 the collection of deferred costs that were approved in prior proceedings. On February 26,TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million).
In March 2010, the Ohio Companies filed an application for a Supplemental Stipulation,new ESP, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modifiedPUCO approved in August 2010, with certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding con tained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions.modifications. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions tooknew ESP will go into effect on June 1, 2009.
SB2212011 and conclude on May 31, 2014. The material terms of the new ESP include: a CBP similar to the one used in May 2009 and the one proposed on the October 2009 MRO filing (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also requires electricapplies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution utilitiesrates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to implementrecover 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 recover from retail customers certain costs related to the companies’ integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 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, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency programs. and alternative energy requirements. Many of the existing riders approved in the previous ESP remain in effect, with some modifications. The new ESP resolved proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and expenses related to the ESP.
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Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent ofto 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 .75%0.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies have filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the 2009 energy efficiency benchmarks to zero, contingent upon the Ohio Companies meeting the revised benchmarks in a period of not more than three years. On March 10, 2010, the PUCO found that due to a change in PUCO rules subsequent to the filing of the Ohio Companies’ application, the Ohio Companies’ application seeking a reduction of the peak demand reduction requirements was moot.
In its March 10, 2010, Entry the PUCO also found that the Companies peak demand reduction programs complied with PUCO rules.
The Ohio Companies are presently involved in collaborative efforts related to energy efficiency programs, including filing applications for approval of those programs with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. 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 PUCO set the matter for a hearing that was completed on March 8, 2010, and all briefing was completed by April 12, 2010. On March 8, 2010, the Ohio Companies filed their 2009 Status Update Report with the PUCO in which they indicated compliance with the 2009 statutory energy efficiency and peak demand benchmarks as those benchmarks were amended as described above. Interested parties filed comments on the Report. The PUCO has yet to address these comments. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers.
In October 2009, The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. Because of the delay in issuing the Order, the launch of the programs included in the plan for 2010 was delayed and will launch during the second quarter of this year. As a result, OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks. Therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. Moreover, because the PUCO issued additional Entries modifying certain of its previous rulesindicated, when approving the 2009 benchmark request, that set outit would modify the manner in which electric utilities, includingCompanies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies will be requiredwere not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring these them into compliance with their yet-to-be-defined modified benchmarks. Failure to comply with the benchmarks containedor to obtain such an amendment may subject the Companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in SB221the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the employmentoriginal CFL program that the Ohio Companies had previously suspended at the request of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements.the PUCO. Applications for rehearingRehearing were filed in mid-November 2009 were granted on December 9, 2009 for the sole purpose of further considerationApril 22, 2011, regarding portions of the matters raised in those applications. ThePUCO’s decision, including the method for calculating savings and certain changes made by the PUCO has not yet issued a substantive Entry on Rehearing. The rules implementing the requirements of SB221 went into effect on December 10, 2009.
to specific programs.
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 serveserved 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 will bewere used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. On December 7, 2009, the Ohio Companies filed an application with the PUCO seeking a force majeure determination regarding the Ohio Companies’ compliance with the 2009 solar energy resources benchmark, and seeking a reduction in the benchmark. OnIn March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and thus granted the Ohio Companies’ application seeking force majeure.market. The PUCO reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies’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. On April 15, 2010, the Ohio Companies and FES (due to its status as an electric service company in Ohio) filed compliance reports with the PUCO setting forth how they individually satisfied the alternative energy requirements in SB221 for 2009. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark which application is still pending.
On October 20,by the amount of SRECs that FES was short of in its 2009 benchmark. In July 2010, the Ohio Companies filedinitiated an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBPadditional RFP to secure generation supply for customers who do not shop with an alternative supplierRECs and would be similar, in all material respects,solar RECs needed to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility and supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009. Hearings took place in December 2009 and the matter has been fully briefed. Pursuant to SB221, the PUCO ha s 90 days from the date of the application to determine whether the MRO meets certain statutory requirements. Althoughmeet the Ohio Companies requested a PUCO determination by January 18,Companies’ alternative energy requirements as set forth in SB221 for 2010 on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements are met, the Ohio Companies would be able to implement the MRO and conduct the CBP.
2011 and executed related contracts in August 2010. On March 23, 2010,April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. The PUCO has not yet acted on that application.
In February 2010, OE and CEI filed an application with the PUCO to establish a new ESP, which if approved bycredit for all-electric customers. In March 2010, the PUCO would go into effectordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on June 1, 2011December 31, 2008 and conclude on May 31, 2014. Attached to the application was a Stipulation and Recommendation signed byauthorized the Ohio Companies to defer incurred costs equivalent to the Staff ofdifference 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 in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and anauthorized deferral for the associated additional fourteenamounts. 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 signing as Signatory Parties, with two additional parties agreeing not to oppose the adoption of the Stipulation. The material terms of the Stipulation includeseek a CBP similarlong term solution to the one usedissue. Tariffs implementing this newly expanded credit went into effect in May 20092010 and the one proposedproceeding remains open. The hearing on the matter was held in the October 2009 MRO filing; a 6% generation discount to certain low-income customers provided byFebruary 2011. The matter has now been briefed and the Ohio Companies through a bilateral wholesale contract with FES; no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider D CR), to recover a return of, and on, capital investments inawait the delivery system. This Rider replaces the Delivery Service Improvement Rider (Rider DSI) which terminates by its own terms. The Ohio Companies also agree not to collect certain amounts associated with RTEP and administrative costs associated with the move to PJM. Many of the existing riders approved in the previous ESP remain in effect, some with modifications. The new ESP also requests the resolution of current proceedings pending at the PUCO regarding corporate separation, elements of the smart grid proceeding and the move to PJM. The evidentiary hearing began on April 20, 2010, at the PUCO. The Stipulation requested a decision by the PUCO by May 5, 2010. On April 28, 2010, the PUCO Chairman issued a statement that the PUCO will not issue a decision on May 5, 2010, and will take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP.PUCO’s decision.
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Pennsylvania
Pennsylvania
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations.
On February 20, 2009, 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 via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan proposes a staggered procurement schedule, which varies by customer class. On September 2, 2009, the ALJ issued a Recommended Decision (RD) approving the settlement and adopted the Met-Ed and Penelec’s positions on two reserved issues. On November 6, 2009, the PPUC entered an Order approving the settlement and finding in favor of Met-Ed and Penelec on the two reserved issues. Generation procurement began in January 2010.
On May 22, 2008, the PPUC approved Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded. On August 11, 2009, the ALJ issued a Recommended Decision to the PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The PPUC adopted a Motion on January 28, 2010 and subsequently entered an Order on March 3, 2010 which deniesthat denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directsdirected Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructsinstructed 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. OnIn 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 loss costs. By Order entered March 25, 2010, thelosses. The PPUC granted the requested stay until December 31, 2010. OnPursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and for the use of these funds to mitigate future generation rate increases which the PPUC approved. In 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. The argument before the Commonwealth Court, en banc, was held in December 2010. Although the ultimate outcome of this matter cannot be determined at this time, it is the belief of Met-Ed and Penelec believe that they should prevail in the appeal and therefore expect to fully recover the approximately $199.7$252.7 million ($158.5188.0 million for Met-Ed and $41.2$64.7 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011. On April 2,
In May 2008, May 2009 and May 2010, Met-Ed and Penelec filed a Response to the PPUC’s March 3, 2010 Order requesting approval of procedures to establish separate accounts to track all marginal transmission loss revenues and related interest and the use of those funds to mitigate future generation rate increases commencing January 1, 2011
On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the periodannual periods between June 1, 2009 through May2008 to 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, as requiredabove. The PPUC’s approval in connection withMay 2010 authorized an increase to the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC resulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers increased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, the PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPU C’s May 2008 Order and defer $57.5 million of projected costs to a future TSC to be fully recoveredprovide for full recovery by December 31, 2010. Under this proposal, monthly bills
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. In August 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 in November 2009. Generation procurement began in January 2010.
In February 2010, Penn filed a Petition for Met-Ed’s customers would increase approximately 9.4%Approval of its Default Service Plan for the period June 20091, 2011 through May 2010.31, 2013. In July 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.
Pennsylvania adopted Act 129 became effective in 2008 and addressesto address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C PlansAct 129 also required utilities to file with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 O rder. Following evidentiary hearings and further revisions to the EE&C Plans, the Pennsylvania Companies filed final plans and tariff revisions on February 5, 2010 consistent with the minor revisions required by the PPUC. Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order onin February 26, 2010 approvinggiving final approval to all aspects of the final plansEE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010.
Act 129 also required utilities to fileWP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by August 14,Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the PPUCCommonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter technology procurementimplementation in the EE&C Plan, and installationthat inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan to provide fordoes not meet the installationTotal Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September, 2010, WP filed an amended EE&C Plan that is less reliant on smart meter technology within 15 years. On August 14, 2009, deployment, which the PPUC approved in January 2011.
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Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan. ConsistentSMIP with the PPUC’s rules, thisPPUC in August 2009. This plan proposesproposed 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 atof approximately $29.5 million, which the Pennsylvania Companies, in their plan, proposed to recover through an automatic adjustment clause. An Initial Decision was issued by the presiding ALJ on January 28, 2010. The ALJ’s Initial Decision approved the Smart Meter PlanSMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; eliminatingdenying the provisionrecovery of interest inthrough the 1307(e) reconciliation;automatic adjustment clause; providing for the recovery of reasonable and prudent costs minusnet of resulting savings from installation and use of smart meters; and reflectingrequiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. OnIn 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 Smart Meter Implementation Plan (SMIP)SMIP for the Pennsylvania Companies. An orderMet-Ed, Penelec and Penn. The PPUC entered its Order in June 2010, consistent with Chairman Cawley’s Motionthe Chairman’s Motion. 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, which the PPUC granted in part 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.
In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, which contemplated deployment of 375,000 smart meters by May 2012, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.
In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s Office of Consumer Advocate filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.
In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is anticipated t o be enteredconsidered and that the Joint Petition for Settlement has adequate support in the near future,record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in which eventOctober 2010, adds the Pennsylvania Companies will move forwardPPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the Smart Meter Technology Procurement and Installation Plan.
Legislation addressing rate mitigation andOSBA was also filed on March 9, 2011. The proposed settlement remains subject to review by the expiration of rate caps was introduced inALJ, who will prepare an Initial Decision for consideration by the legislative session that ended in 2008; several bills addressing these issues were introduced in the 2009 legislative session. The final form and impact of such legislation is uncertain.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec fi led tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the Pennsylvania Companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings.
PPUC.
By Tentative Order entered in September 17, 2009, the PPUC provided for an additional 30-day comment period on whether “thethe 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 over-collectioncosts for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order, the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliancevarious parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec filed reply comments on October 26, 2009. On November 5, 2009, the PPUC issued a Secretarial Letter allowing parties to file reply comments to Met-Ed and Penelec’s reply co mments by November 16, 2009, and reply comments were filed by the Office of Consumer Advocate, ARIPPA, and the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance. Met-Ed and Penelec are awaiting further action by the PPUC.
In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. The PPUC has not yet initiated that investigation.
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In September 2010, PATH-VA filed an application with the Virginia SCC for authorization to construct the Virginia portions of the PATH Project. On February 8, 2010, Penn28, 2011, PATH-VA filed a motion to withdraw the application. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
West Virginia
In August 2009, MP and PE filed with the PPUCWVPSC a generation procurement plan coveringrequest to increase retail rates by approximately $122.1 million annually, effective June 10, 2010. In January 2010, MP and PE filed supplemental testimony discussing a tax treatment change that would result in a revenue requirement approximately $7.7 million lower than the period June 1, 2011 through May 31, 2013. The plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposed a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. A preliminary conference was held on March 26, 2010, and, among other things, established a procedural schedule. Evidentiary hearings are scheduled for June 15-16, 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010.
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 March 31, 2010, the accumulated deferred cost balance totaled approximately $55 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and al so submitted commentsrequirement included in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. 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. 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 EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments. The EMP was issued on October 22, 2008, establishing five major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, 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 BPU issued an order indefinitely suspending the requirement of the 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.
In support of former New Jersey Governor Corzine's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations.original filing. In addition, approximately $34 million would be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million would be spent on energy efficiency, specifically replacing transformersin December 2009, subsidiaries of MP and capacitor control systems and installing new LED street lights. The remaining $13 million would be spent on energy efficiency programs that would complement those currently being offered. The project relatingPE completed a securitization transaction to expansion of the existing demand response programs was approved by the NJBPU on August 19, 2009, and implementation began in 2009. Approval for the project related to energy efficiency programs intended to complement those currently being offered was denied by the NJBPU on December 1, 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of thefinance certain costs associated with the proposal.installation of scrubbers at the Fort Martin generating station, which costs would otherwise have been included in the request for rate recovery. Consequently, MP and PE ultimately requested an annual increase in retail rates of approximately $95 million, rather than $122.1 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:
a $40 million annualized base rate increase effective June 29, 2010;
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a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;an additional $20 million annualized base rate increase effective in January 2011;
Ona decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and
a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.
The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.
In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the Companies in meeting their combined requirements under the Portfolio Act. Further, in February 11, 2010, S&P downgraded2011, MP and PE filed a petition with the senior unsecured debt of FirstEnergy Corp.WVPSC seeking an Order declaring that MP is entitled to BB+. As a result,all alternative & renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville, the requirementsowner of a pre-existing NJBPU order, JCP&L filed, on February 17, a plan addressing the mitigation of any effectone of the downgrade and which providedcontracted resources, has filed an assessment of present and future liquidity necessaryopposition to assure JCP&L’s continued payment to BGS suppliers. The NJBPU subsequently held a public hearing to review the plan and available options. On March 17, 2010, the NJBPU determined that JCP&L demonstrated that it has ample resources available to continue uninterrupted payments to BGS suppliers and that there are no concerns with JCP&L's liquidity and therefore no further action is required.
Petition.FERC Matters
Rates for Transmission Service betweenBetween MISO and PJM
OnIn 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 the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. TheIn 2005, the FERC issued orders in 2005 settingset the SECA for hearing. The presiding judgeALJ issued an initial decision onin August 10, 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision is subj ectwas subject to review and approval by the FERC. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008,In May 2010, FERC issued an order approving uncontesteddenying 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 but did not rule onwith AEP, Dayton and the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, March 17, 2010 and April 8, 2010, FirstEnergy, filed additional settlement agreements with FERC to resolve outstanding claims with various parties. FirstEnergy is actively pursuing settlement agreements with otherExelon 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 case. On December 8, 2009, certain parties sought a writ of mandam us from the DC Circuit Court of Appeals directing FERC to issue an order on the Initial Decision.SECA period. The Court agreed to hold this matter in abeyance based upon FERC’s representation to use good faith efforts to issue a substantive ruling on the initial decision no later than May 27, 2010. If FERC fails to act, the case will be submitted for briefing in June. The outcome of this matter cannot be predicted.
PJM Transmission Rate
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previouslyAEP, Dayton and Exelon, settlements were approved by the FERC. JCP&L, Met-EdFERC in November 2010, and Penelec were partiesthe relevant payments made. The Utilities have refund obligations that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy are not expected to that proceeding and joinedbe material. Rehearings remain pending in two of the filings. this proceeding.
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PJM Transmission Rate
In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held on the content of the compliance filings and numerous parties appeared and litigated various issues concerning PJM rate design, notably AEP, which proposed to create a "postage stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. AEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zone s, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the 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, the 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.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” basis. The FERC found that PJM’s current beneficiary-paysapproach to allocating the cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and rea sonable cost allocation methodology for inclusion in PJM’s tariff.
high voltage transmission facilities.
The FERC’s April 19, 2007Opinion 494 order and related order denying a request for rehearing werewas appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision onin 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 postage-stampload ratio share basis and, based on this finding, remanded the rate design issue back to FERC. A request for rehearing and rehearing en banc by two companies was denied by the Seventh Circuit on October 20, 2009.
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 within 45 days, and then reply comments 30 days later.on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. InterestedPJM’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 the costs. Numerous parties may filefiled responsive comments or studies byon May 28, 2010. Reply2010 and reply comments are due byon June 28, 2010.
The FERC’s orders on PJM rate design prevented the allocation of FirstEnergy and a portion of the revenue requirement of existing transmission facilitiesnumber of other utilities, to JCP&L, Met-Edindustrial customers and Penelec. In addition,state commissions supported the FERC’s decision to allocateuse of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of new 500 kV and above transmission facilitiesthese costs on a postage-stamp basis reducesload ratio share basis. This matter is awaiting action by the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. FERC has no specific time frame to rule in this matter.FERC.
RTO Consolidation
Realignment
On August 17, 2009, FirstEnergyFebruary 1, 2011, ATSI in conjunction with PJM filed an applicationits proposal with the FERC requesting to consolidatefor moving its transmission assets and operationsrate into PJM. Currently, FirstEnergy’s transmission assets and operations are divided betweenPJM’s tariffs. FirstEnergy expects ATSI to enter PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM. Key elements of the filing include a Fixed Resource Requirement Plan (FRR Plan) that describes the means whereby capacity will be procured and administered as necessary to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years; and also a request that ATSI’s transmission customers be excused f rom the costs for regional transmission projects that were approved through PJM’s RTEP process prior to ATSI’s entry into PJM (legacy RTEP costs). The integration is expected to be complete on June 1, 2011, and that if legal proceedings regarding its rate are outstanding at that time, ATSI will be permitted to coincide with deliverystart charging its proposed rates, subject to refund. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of power undercollecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the next competitive generation procurement processMISO submitted numerous filings for the Ohio Companies. To ensure a definitive ruling atpurpose of effecting movement of the same timeATSI zone to PJM on June 1, 2011. These filings include clean-up of the FERC rules on its requestMISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to integrate ATSIreflect the move into PJM, on Octoberand submission of changes to PJM’s tariffs to support the move into PJM.
FERC proceedings are pending in which ATSI’s transmission rate, the exit fee payable to MISO, transmission cost allocations and costs associated with long term firm transmission rights payable by the ATSI zone upon its departure from the MISO are under review. The outcome of these proceedings cannot be predicted.
MISO Multi-Value Project Rule Proposal
In July 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, 2009,2010, 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 $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.
In September 2010, FirstEnergy filed a related complaintprotest 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 FERCestablished rule that cost allocation is to be based on the issuecost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of exemptingprogress to date in the ATSI footprint from the legacy RTEP costs.
On September 4, 2009, the PUCO opened a caseintegration into PJM, it would be unjust and unreasonable to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation. Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integrationallocate any MVP costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO.the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
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OnIn December 17, 2009,2010, FERC issued an order approving subjectthe MVP proposal without significant change. FERC’s order was not clear, however, as to certain future compliance filings,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 move to PJM. FirstEnergy’s requestexit but ruled that the question of the amount of costs that are to be exempted from legacy RTEP costs was rejected and its complaint dismissed.
On December 17, 2009,allocated to ATSI executed the PJM Consolidated Transmission Owners Agreement. On December 18, 2009, the Ohio Companies and Penn executed the PJM Operating Agreement and the PJM Reliability Assurance Agreement. Execution of these agreements committed ATSI and the Ohio Companies and Penn’sor to load to moving into PJM on the schedule described in the applicationATSI zone were beyond the scope of FERC’s order and approvedwould be addressed in the FERC Order (June 1, 2011).
future proceedings.
On January 15, 2010, the Ohio Companies and Penn submitted a compliance filing describing the process whereby ATSI-zone load serving entities (LSEs) can “opt out” of the Ohio Companies' and Penn's FRR Plan for the 2011-12 and 2012-13 delivery years. On January 16, 2010, FirstEnergy filed for clarification or rehearing of certain issues associated with implementing the FRR auctions on the proposed schedule. On January 19, 2010,18, 2011, FirstEnergy filed for rehearing of FERC’s decision to imposeorder. In its rehearing request, FirstEnergy argued that because the legacy RTEPMVP rate is usage-based, costs on ATSI’s transmission customers. Also on January 19, 2010, several parties, including the PUCO and the OCC asked for rehearing of parts of FERC’s order. None of the rehearing parties asked FERC to rescind authorization for ATSI to enter PJM. Instead, parties focused on questions of cost and cost allocation or on alleged errors in implementing the move. On February 3, 2010, FirstEnergy filed an answer to the January 19, 2010 rehearing requests of other parties. On February 16, 2010, FirstEnergy submitted a second compliance filing to FERC; the filing describes communications protocols and performance deficiency penalties for capacity suppliers that are taken in FRR auctions.
On March 10, 2010, FERC granted FirstEnergy’s request for expedited hearing on the conduct of the FRR auctions. The Ohio Companies and Penn obtained their PJM capacity requirements for the 2011 and 2012 delivery years in the FRR auctions conducted March 15-19, 2010. The PJM market monitor certified the FRR auction results on March 25, 2010, and the auction results were released by PJM on March 26, 2010. On March 29, 2010, the Ohio Companies and Penn signed agreements with all winning suppliers. In May 2010, the Ohio Companies and Penn’s load will be included in the PJM Base Residual Auction for the delivery year beginning 2013. FirstEnergy and unaffiliated generation and loads in the ATSI footprint are also expected to participate in the Base Residual Auction. FirstEnergy expects to integrate into PJM effective June 1, 2011.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the FPA. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January 2009. The request for settlement hearings was granted. Settlement hadapplied to ATSI, which is a stand-alone transmission company that does not been reached by January 9, 2009use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and accordingly, F irstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, impropriety of allocating costs to the ATSI zone or to ATSI. FirstEnergy cannot predict the outcome of these proceedings at this time.
PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008 apply.
Calculation ErrorOnIn March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. It ordered changes included making incremental improvements to RPM and clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.
MISO Complaints Versus PJM
On March 9, 2010, MISO filed two complaints at FERC against PJM with FERC under Sections 206, 306,relating to a previously-reported modeling error in PJM’s system that impacted the manner in which market-to-market power flow calculations were made between PJM and 309 of the FPA alleging violations of the MISO/MISO since April 2005. MISO claimed that this error resulted in PJM Joint Operating Agreement (JOA). In the first complaint,underpaying MISO alleged that by failing to account for the market flows from 34 PJM generatorsapproximately $130 million over the time period from 2007-2009, PJM underpaid MISO by a total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM of at least $12 million plus interest. MISO also claimed that PJM failed to maintain required records necessary to calculate underbilling for the 2005-2007 billing.
In the second complaint,in question. Additionally, MISO alleged that PJM has refuseddid not properly trigger market-to-market settlements between PJM and MISO during times when it was required to comply with provisionsdo so, which MISO claimed may have cost it $5 million or more. As PJM market participants, AE Supply and MP may be liable for a portion of the JOA requiring market-to-market dispatch since 2009,any refunds ordered in this case. PJM, Allegheny and is improperly demanding repayment of redispatch payments previously madeother PJM market participants filed responses to MISO.
PJM filed its answers to theMISO complaints on April 12, 2010, opposing the relief sought by MISO. In addition, on April 12, 2010,and PJM filed a related complaint withat FERC pursuant to Section 206, 306, and 309 allegingagainst MISO claiming that MISO is violating the JOA with PJM by initiating market-to-market coordination and financial settlementsimproperly called for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM claims that the JOA does not permit MISO to initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantiallyseveral times during the same time period covered by the two MISO complaints filed against PJM, which PJM claimed may have cost PJM market participants $25 million or more. On January 4, 2011, an Offer of Settlement was filed at FERC that, if approved, would resolve all pending issues asin the second MISO complaint, in which MISO argues thatdispute. The Offer of Settlement calls for the usewithdrawal of proxy flowgates is permittedall pending complaints with no payments being made by agreementany parties. Initial comments on the Offer of the RTOsSettlement were filed at FERC on January 24, 2011. FirstEnergy and operating practice. Each party filed a complaint in order to ensure their right to claim refunds, if any, if successful in their arguments at FERC.
FirstEnergy has intervened in all three proceedings, and timelyAllegheny Energy filed comments supporting MISOthe proposed settlement. A report on the partially contested settlement was issued by the settlement judge to the FERC on March 9, 2011. On March 16, 2011, the settlement judge terminated the settlement proceedings and forwarded the partially contested settlement to the FERC for review. The case is awaiting a decision by the FERC.
California Claims Matters
In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by the FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to the FERC, which arises out of claims previously filed with the FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers have filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. In April 2010, the California parties filed exceptions to the judge’s ruling with the FERC, and briefing is complete on those exceptions. The parties are awaiting a ruling from the FERC on the exceptions.
In June 2009, the California Attorney General, on behalf of certain California parties, filed a second lawsuit with the FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for the joining of AE Supply in this new lawsuit. AE Supply has filed a motion to dismiss the Brown case that is pending before the FERC. No scheduling order has been entered in the Brown case. Allegheny intends to vigorously defend against these claims but cannot predict their outcome.
Transmission Expansion
TrAIL Project.TrAIL is a 500 kV transmission line currently under construction that will extend from southwest Pennsylvania through West Virginia and into northern Virginia. On April 15, 2011, the TrAIL 500 kV line segment from Meadowbrook substation to Loudoun substation in Virginia was successfully energized and is carrying load. The other segments are planned to be energized in May. The entire TrAIL line is scheduled to be completed and placed in service no later than June 2011.
PATH Project.The PATH Project is comprised of a 765 kV transmission line that is proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.
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PJM initially authorized construction of the PATH Project in June 2007 and, on June 17, 2010, requested that PATH, LLC proceed with all efforts related to the PATH Project, including state regulatory proceedings, assuming a required in-service date of June 1, 2015. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its first complaint,2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the potential need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC and the WVPSC has granted the motion to withdraw. The VSCC has not ruled on the motion to withdraw.
PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to improper accountingthe formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of market flows resultinga return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in underpayments from 2005-2009.settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity. FirstEnergy is unable tocannot predict the outcome of this matter.proceeding or whether it will have a material impact on its operating results.
Sales to Affiliates
FES has received authorization from the FERC to make wholesale power sales to affiliated regulated utilities in New Jersey, Ohio, and Pennsylvania. FES actively participates in auctions conducted by or on behalf the regulated affiliates to obtain power necessary to meet the utilities’ POLR obligations. AE Supply, a merchant affiliate acquired in the FirstEnergy-Allegheny merger, also participates in these auctions, and obtains prior FERC authorization when necessary to make sales to FE affiliates.
Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergyCompliance with regard to environmental mattersregulations could have a material adverse effect on FirstEnergy'sFirstEnergy’s earnings and competitive position to the extent that itFirstEnergy 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.
CAA Compliance
FirstEnergy accrues environmental 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. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 and NOx emissions regulations.regulations under the CAA. FirstEnergy complies with SO2 and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. penalties.
The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis, Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired pla ntsplants 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 repoweringrepowering. OE and provides forPenn are subject to stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $399 million for 2010-2012.
In October 2007, PennFuture and three of its members filed a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations, in the U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional 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. In addition to seeking damages, twoTwo of the threethese 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 representa tives. On October 16, 2009, a settlement reached with PennFuture and one of the three individual complainants was approved by the Court, which dismissed the claims of PennFuture and of the settling individual. The other two non-settling individuals are now represented by counsel handling the three cases filed in July 2008.representatives. FGCO believes thosethe claims are without merit and intends to defend itself against the allegations made in thosethese three complaints.
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The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009, which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.
In December 2007, the statestates of New Jersey and Connecticut filed a CAA citizen suitsuits in 2007 alleging NSR violations at the Portland Generation Station against Reliant (theGenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jerseythese suits allege that "modifications"“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting underin violation of the CAA'sCAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. Met-Ed filed a Motion to DismissIn September 2009, the claims in New Jersey’s Amende d Complaint and Connecticut’s Complaint in February and September of 2009, respectively. The Court granted Met-Ed'sMet-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 on statutepenalties. The parties dispute the scope of limitations grounds in orderMet-Ed’s indemnity obligation to allowand from Sithe Energy, and Met-Ed is unable to predict the states to prove either that the applicationoutcome of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.this matter.
In January 2009, the EPA issued a NOV to ReliantGenOn Energy, Inc. alleging NSR violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 2009, NOV1986 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. (Mission) alleging that "modifications"“modifications” at the Homer City Power Station occurred sincefrom 1988 to the present without preconstruction NSR or permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in the Homer City Power Station containing in all material respects allegations identical to those included in the June 2008 NOV. On July 20, 2010, the states of New York and Pennsylvania provided Mission, 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'sCAA. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec 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 program.and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of the Homer City Station, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on the Homer City Station’s air emissions as well as 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, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding the Homer City Station seeking injunctive relief and civil penalties. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) 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 is disputed.under dispute and Penelec is unable to predict the outcome of this matter.
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. In September 2009, FGCO received an informationa request pursuant to Section 114(a) of the CAA requestingfor certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shorefor these same generating plants and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generati nggenerating plant may constitute a major modification under the NSR provision of the CAA. On December 23,Later in 2009, FGCO also received another information request regarding emission projections for the Eastlake generating plant pursuant to Section 114(a) of the CAA.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. A June 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.
In August 2008, FirstEnergy2000, AE received a requestletter from the EPA forrequesting that it provide information pursuantand documentation relevant to the operation and maintenance of the following ten electric generation facilities, which collectively include 22 generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island. The letter requested information under Section 114(a)114 of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complyingcompliance with the NSR provisionsCAA and related requirements, including potential application of the CAA. FirstEnergy intendsNSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to fully comply with the EPA’s informationthis and a subsequent request but at this time, is unable to predict the outcome of this matter.
In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired facilities: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell generation facilities in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.
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In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell facilities in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. In May 2006, the District Court denied Allegheny’s motion to dismiss the amended complaint. In July 2006, the Court determined that discovery would proceed regarding liability issues, but not remedies. Discovery on the liability phase closed on December 31, 2007, and summary judgment briefing was completed during the first quarter of 2008. In November 2008, the District Court issued a Memorandum Order denying all motions for summary judgment and establishing certain legal standards to govern at trial. In December 2009, a new trial judge was assigned to the case, who then entered an order granting a motion to reconsider the rulings in the November 2008 Memorandum Order. In April 2010, the new judge issued an opinion, again denying all motions for summary judgment and establishing certain legal standards to govern at trial. The non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong generation facilities in Pennsylvania and the Fort Martin and Willow Island generation facilities in West Virginia.
FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO2 and NOX, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO2 emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith power station for NOX, SO2 and mercury, based on a PJM declaration that the station is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NOX and SO2 limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO2 emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants generating facility. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states.The EPA’s CAIR requires reductions of NOXNOx and SO2 emissions in two phases (Phase I in 2009 for NOX, (2009/2010 for SO2and Phase II in 2015 for both NOX and SO2)2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOXNOx emissions to 1.3 million tons annually. CAIR was challenged inIn 2008, the U.S. Court of Appeals for the District of Columbia and on July 11, 2008, the CourtCircuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In September 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. 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 July 11, 2008Court’s opinion. On July 10, 2009, the U.S.The Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX“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"“8-hour” ozone NAAQS. FGCO'sIn July 2010, the EPA proposed the Clean Air Transport Rule (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 with these regulations may be substantialsubstantial. Management is currently assessing the impact of these environmental proposals and will depend, in part,other factors on FGCO’s facilities, particularly on the action taken by the EPA in responseoperation of its smaller, non-supercritical units. For example, as disclosed herein, management decided to the Court’s ruling.idle certain units or operate them on a seasonal basis until developments clarify.
Hazardous Air Pollutant Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions 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. Several states and environmental groups appealed the CAMR to the U.S . Court of Appeals for the District of Columbia. On February 8, 2008, the Court 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. The EPA petitioned for rehearing by the entire Court, which denied the petition in May 2008. In October 2008, the EPA (and an industry group) petitioned the U.S. Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On April 15, 2010, the EPA entered into a consent decree requiring it to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. On April 29, 2010, the EPA issued proposedreleased its MACT regulations requiring emissions reductions ofproposal to establish emission standards for mercury, hydrochloric acid and other hazardous air pollutants from non-electric generating unit boilers, including boilers which do not use fossil fuels such as the proposed Burger biomass repowering project. If finalized, the non-electric generating unit MACT regulations could also provide precedentvarious metals for MACT standards applicable to electric generating units. Depending on the action taken by the EPA and on how any future regulations are ultimately implemented, FGCO’sFirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’sFirstEnergy’s operations may result.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The U.S. signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the U.S. Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. 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.
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, in June 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, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI 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 required FirstEnergy to measure GHG emissions commencing in 2010 and will require it 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 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. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO2 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 whichthat recognized the scientific view that the increase in global temperature should be below two degrees Celsius, includedCelsius; includes 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 2020,2020; and establishedestablishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. OnceTo the extent that 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. 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. 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.
On April 2, 2007, the U.S. Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. 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. Also in September 2009, the EPA proposed new thresholds for GHG emissions that define when CAA permits under the NS R and Title V operating permits programs would be required. The EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. The EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit. 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 GHG increase the threat of climate change. In April 2010, EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles requiring an estimated combined average emissions level of 250 grams of CO2 per mile in model year 2016 and clarified that GHG regulation under the CAA will not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest.
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. On February 6, 2010,However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit granted defendants’ petition for rehearing en banc and on April 30, 2010,reinstated the Fifth Circuit cancelled the en banc hearing. On March 5, 2010, the Second Circuit denied defendants’ petition for rehearing and rehearing en banc.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 contribu tecontribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. Oral argument was held on April 19, 2011, and a decision is expected by July 2011. While FirstEnergy is not a party to eitherthis litigation, should the courts of appeals decisions be affirmed or not subjected to further review, 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 of its 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'sFirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvaniathe states in which FirstEnergy operates have water quality standards applicable to FirstEnergy'sFirstEnergy’s operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, theThe 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 large 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'sfacility’s cooling water system). On January 26, 2007,The EPA has taken the U.S. Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, notingposition that until further rulemaking occurs, permitting authoritie sauthorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. OnIn April 1, 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit Court’sCircuit’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. TheOn March 28, 2011, the EPA is developingreleased a new proposed regulation under Section 316(b) of the Clean Water Act consistent withgenerally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the opinionsmajority of the Supreme Courtour existing generating facilities to assist permitting authorities to determine whether and the Courtwhat site-specific controls, if any, would be required to reduce entrainment of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard.aquatic life. FirstEnergy is studying various control options and their costs and effectiveness.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. In November 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 profess ionalprofessional judgment, the future costs of compliance with these standards may require material capital expenditures.
TheIn April 2011, the U.S. Attorney'sAttorney’s Office in Cleveland, Ohio has advised FGCO that it is no longer 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. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.
Monongahela River Water Quality
In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry generation facility. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin on September 13, 2011. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.
In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. EPA has not acted on PA DEP’s recommendation. If the designation is approved, Pennsylvania will then need to develop a TMDL limit for the river, a process that will take about five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.
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In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.
Regulation of Waste Disposal
AsFederal 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, federal and state hazardous waste regulations have been promulgated.1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA'sEPA’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 regulationwhether they should be regulated as hazardous or non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion residuals.
In December 2009, the EPA provided to FGCO the findings of its review of t he Bruce Mansfield Plant’s coal combustion residuals management practices. The EPA observed that the waste management structures and the Plant “appeared to be well maintained and in good working order” and recommended only that FGCO “seal and maintain all asphalt surfaces.” On December 30, 2009, in an advanced notice of public rulemaking, the EPA saidasserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. OnIn May 4, 2010, the EPA issued a proposed rule that provides 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'sFirstEnergy��s future cost of compliance with any coal combustion residuals regulations whichthat 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 UtilitiesUtility Registrants 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 March 31, 2010,2011, based on estimates of the total costs of cleanup, the Utilities'Utility Registrants proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $101$104 million (JCP&a mp;L - $74&L — $69 million, TE -— $1 million, CEI -— $1 million, FGCO -— $1 million and FirstEnergy - $24— $32 million) have been accrued through March 31, 2010.2011. Included in the total are accrued liabilities of approximately $67$64 million for environmental remediation of former manufactured gas plants 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.&L. 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'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. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1)On July 29, 2010, the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage mo del or individual proof of damages. On March 31, 2009,upheld the trial court again granted JCP&L’s motion to decertifycourt’s decision decertifying the class. On April 20, 2009, the Plaintiffs have filed, and JCP&L has opposed, a motion for leave to take an interlocutory appeal to the trial court's decision to decertifyNew Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class which was granted by the Appellate Division on June 15, 2009. Plaintiffs filedaction attempt, and leaves only nine (9) plaintiffs to pursue their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filedrespective individual claims. The remaining individual plaintiffs have not taken any affirmative steps to pursue their reply brief in further support of their appeal of the trial court's decision decertifying the class. The Appellate Division heard oral argument on January 5, 2010, before a three-judge panel. JCP&L is awaiting the Court’s decision.individual claims.
Litigation Relating to the Proposed Allegheny Energy Merger
In connection with the proposed merger (Note 14), purported shareholders of Allegheny Energy have filed putative shareholder class action and/or derivative lawsuits in Pennsylvania and Maryland state courts, as well as in the U.S. District Court for the Western District of Pennsylvania, against Allegheny Energy and its directors and certain officers, referred to as the Allegheny Energy defendants, FirstEnergy and Merger Sub. The lawsuits allege, among other things, that the Allegheny Energy directors breached their fiduciary duties by approving the merger agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The plaintiffs allege that the merger consideration is unfair, that other terms in the merger agreement including the termination fee and the non-solicitation provision s are unfair, that certain individual defendants are financially interested in the merger, and that Allegheny Energy has failed to disclose material information about the merger to its shareholders. Among other remedies, the plaintiffs seek to enjoin the merger and they have demanded jury trials. The Allegheny Energy defendants moved to consolidate the Maryland lawsuits and filed motions to dismiss and answers to each of the Maryland complaints. The court consolidated the Maryland lawsuits and an amended complaint has been filed. The Allegheny Energy defendants, FirstEnergy, and Merger Sub filed motions to dismiss the amended complaint on April 21, 2010. The Maryland court has set a hearing for argument on the motions to dismiss for June 3, 2010. By order dated April 26, 2010, the Maryland court certified a plaintiff class that consists of all holders of Allegheny Energy shares at any time from February 11, 2010 to the consummation of the proposed merger. The Pennsylvania state court has consolidat ed the lawsuits filed in that court. The Allegheny Energy defendants and FirstEnergy have moved to stay the Pennsylvania lawsuits and the plaintiff has moved for leave to take expedited discovery. The Pennsylvania state court will hear argument on both motions on May 27, 2010. By stipulation dated April 14, 2010, no response is due to the complaint filed in the U.S. District Court for the Western District of Pennsylvania until June 10, 2010. While FirstEnergy and Allegheny Energy believe the lawsuits are without merit and intend to defend vigorously against the claims, the outcome of any such litigation is inherently uncertain. If a dismissal is not granted or a settlement is not reached, these lawsuits could prevent or delay the completion of the merger and result in substantial costs to FirstEnergy and Allegheny Energy. In accordance with its bylaws, Allegheny Energy will advance expenses to and, as necessary, indemnify all of its directors in connection with the foregoing proceedings. All applicable insur ance policies may not provide sufficient coverage for the claims under these lawsuits, and rights of indemnification with respect to these lawsuits will continue whether or not the merger is completed. The defense or settlement of any lawsuit or claim that remains unresolved at the time the merger closes may adversely affect FirstEnergy’s business, financial condition or results of operations.
Nuclear Plant Matters
Davis Besse Control Rod Drive Mechanism Nozzles
During a planned refueling outage at Davis Besse that began on February 28, 2010, FENOC initially identified 16 of the 69 control rod drive mechanism (CRDM) nozzles that required modification. The Nuclear Regulatory Commission was notified of these findings, along with federal, state and local officials. The initial nozzle inspection process included ultrasonic (UT) testing and visual inspections. On March 18, 2010, the NRC sent a special inspection team to Davis-Besse.
FENOC has begun a comprehensive investigation to determine the underlying cause for the cracking, and retained a contractor to make the necessary modifications. Modifications will be made using a proven industry method subject to NRC review. Further evaluation and testing identified 8 additional nozzles requiring modification. Additional testing will be conducted following the modification of each nozzle to ensure safe, reliable plant operations. The plant is expected to be ready for restart in July, 2010.
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 such time that 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. What actions, if any, the NRC takes in response to this request have yet to be determined.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of obligations. As of March 31, 2010,2011, FirstEnergy had approximately $1.9$2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis Besse,Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy providedprovides an additional $80$15 million parental guarantee associated with the funding of decommissioning costs for these unitsunits. As required by the NRC, FirstEnergy annually recalculates and indicated that it plannedadjusts 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 contributefund the trusts may increase. Disruptions in the capital markets and their 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 with the decommissioning of FirstEnergy’s nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. This estimate encompasses the shortfall covered by the existing $15 million parental guarantee. FENOC agreed to increase the parental guarantee to $95 million within 90 days of the submittal.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional $80 milliontwenty years, until 2037. By an order dated April 26, 2011, the NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions regarding (1) a combination of renewable alternatives to the renewal of Davis-Besse’s operating license, and (2) the cost of mitigating a severe accident at Davis-Besse. FENOC is currently evaluating these trusts by 2010. Bydevelopments and considering an appropriate response. On April 14, 2011, a letter dated March 8, 2010, primarilygroup of environmental organizations petitioned the NRC Commissioners to suspend all pending nuclear license renewal proceedings, including the Davis-Besse proceeding, to ensure that any safety and environmental implications of the Fukushima Daiichi Nuclear Power Station event in Japan are considered.
In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the Beaver V alley Power Station operating license renewal, FENOC requestedDOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the NRC reducelitigation of these claims. FirstEnergy parental guaranteefiled damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to $15 millionreview and notified the staff that it no longer planned to make the additional contributions into the trusts. FirstEnergy is awaiting the NRC’s decision on the proposed reduction of the parental guarantee.audit by DOE.
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.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. OnIn February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The parties participated in the federal court's mediation programs and held private settlement discussions. On April 14, 2010, the parties reached a tentative agreement on a settlement package that must be reviewed and approved by the court. JCP&L recognized a liability for the potential $16 million award in 2005, which has been adjusted for post-judgment interest that began to accrue as of February 25, 2009.
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. OnIn 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 ruled on that motionrendered an opinion.
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to dismiss.FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The named-defendant companies will continue to defend these claims including challenging any class certification.
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'sFirstEnergy’s or its subsidiaries'subsidiaries’ financial condition, results of operations and cash flows.
NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In 2010, the FASB amended the Derivatives and Hedging TopicSee Note 12 of the FASB Accounting Standards Codification to clarify the scope exception for embedded credit derivative features relatedCombined Notes to the transferConsolidated Financial Statements (Unaudited) for discussion of credit risk in the form of subordination of one financial instrument to another. The amendment addresses how to determine which embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are considered to be embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for the first fiscal quarter beginning after June 15, 2010. FirstEnergy does not expect this standard to have a material effect on its financial statements.new accounting pronouncements.
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FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT'SMANAGEMENT’S NARRATIVE
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'sFirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns FirstEnergy'sFirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES'FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of government aggregation programs, and the sale of electricity toits participation in affiliated utility companies to meet all or a portion of their PLR and default service requirements. FES' revenues also include wholesalenon-affiliated POLR auctions. FES sales non-affiliated customersare primarily concentrated in Ohio, Pennsylvania, New Jersey,Illinois, Maryland, Michigan and Illinois.
New Jersey. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.
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'sFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net incomeEarnings available to parent decreased to $80by $44 million in the first three months of 20102011 compared to $171 million in the same period of 2009.2010. The decrease was primarily due to higher purchased power, fuelincreased transmission expenses, an inventory valuation adjustment, non-core asset impairments and interest expense, partially offset by higher revenues and investment income.mark-to-market accounting.
Revenues
Revenues
Total revenues increased $162$3 million in the first three months of 2011, compared to the same period of 2010, primarily due to an increasegrowth in direct and government aggregation sales, volumes and sales of RECs, partially offset by decreases in PLR sales to the Ohio Companies and wholesalePOLR sales.
The increase in revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended March 31 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Direct and Government Aggregation | | $ | 840 | | | $ | 512 | | | $ | 328 | |
| POLR | | | 369 | | | | 673 | | | | (304 | ) |
| Other Wholesale | | | 96 | | | | 91 | | | | 5 | |
| Transmission | | | 26 | | | | 17 | | | | 9 | |
| RECs | | | 32 | | | | 67 | | | | (35 | ) |
| Other | | | 28 | | | | 28 | | | | — | |
| | | | | | | | | | |
Total Revenues | | $ | 1,391 | | | $ | 1,388 | | | $ | 3 | |
| | | | | | | | | | |
| | | Three Months | | | |
| | | Ended March 31 | | Increase | |
| Revenues by Type of Service | | 2010 | | 2009 | | (Decrease) | |
| | | (In millions) | |
| | | | | | | | |
Direct and Government Aggregation | | | 512 | | | 91 | | | 421 | |
| | | 677 | | | 893 | | | (216 | ) |
| | | 87 | | | 189 | | | (102 | |
| | | 17 | | | 25 | | | (8 | |
| | | 67 | | | - | | | 67 | |
| | | 28 | | | 28 | | | - | |
| | | 1,388 | | | 1,226 | | | 162 | |
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended March 31 | | | Increase | |
| MWH Sales by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In thousands) | | | | | |
| Direct | | | 9,671 | | | | 5,854 | | | | 65.2 | % |
| Government Aggregation | | | 4,310 | | | | 2,732 | | | | 57.8 | % |
| POLR | | | 5,714 | | | | 13,276 | | | | (57.0 | )% |
| Wholesale | | | 1,113 | | | | 898 | | | | 23.9 | % |
| | | | | | | | | | |
Total Sales | | | 20,808 | | | | 22,760 | | | | (8.6 | )% |
| | | | | | | | | | |
DirectThe increase in direct and government aggregation revenues increased $421of $328 million resultingresulted from increased revenue in both the MISO and PJM markets. The increase in revenue is primarily the result of the acquisition of new customers and the inclusion of the transmission-related component in MISO retail rates, partially offset by lower unit prices. The acquisition of new customers is primarily due to new commercial and industrial customers as well asand new government aggregation contracts with communities in Ohio, that provide generationin addition, sales to approximately one million residential and small commercial customers. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.
customers were bolstered by weather in the delivery area that was 5.2% colder than in 2010.PLRThe decrease in POLR revenues decreased $216of $304 million primarilywas due to lower KWH sales volumes to the Pennsylvania and Ohio Companies, and lower unit prices, partially offset by increased sales volumesto non-associated companies and higher unit prices to the Pennsylvania Companies. The lowerParticipation in POLR auctions and RFPs are expected to continue, but the concentration of these sales volumeswill primarily be dependent on our success in our direct retail and unit pricesaggregation sales channels.
Wholesale revenues increased $5 million due to the Ohio Companies in the first three months of 2010 reflected the results of the May 2009 power procurement processes. 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 the first quarter of 2009. The increase was partially offset by lower wholesale prices. The higher sales volumes were the result of increased short term (net hourly position) transactions in MISO. $22 million of wholesale revenue resulted from long positions in MISO that were unable to Pennbe netted with short positions in PJM, due to decreased default serviceseparate settlement requirements in 2010 compared to 2009.
Wholesale revenues decreased $102 million due to a 76.3% decline in volume reflecting market declines, partially offset by higher capacity prices.
within each RTO.
The following tables summarize the price and volume factors contributing to changes in revenues:revenues from generation sales:
Source of Change in Direct and Government Aggregation | | | |
| | | (In millions) | |
| Direct Sales: | | | | |
Effect of 471.5% increase in sales volumes | | $ | 289 | |
Change in prices | | | (30 | ) |
| | | | 259 | |
| Government Aggregation: | | | | |
Effect of an increase in sales volumes | | | 162 | |
Change in prices | | | - | |
| | | | 162 | |
| Net Increase in Direct and Gov’t Aggregation Revenues | | $ | 421 | |
| | | | | | |
| | | | Increase | |
| Source of Change in Direct and Government Aggregation | | | (Decrease) | |
| | | | (In millions) | |
| Direct Sales: | | |
| Effect of increase in sales volumes | | | $ | 223 | |
| Change in prices | | | | (4 | ) |
| | | | | |
| | | | 219 | |
| | | | | |
| Government Aggregation: | | |
| Effect of increase in sales volumes | | | 100 | |
| Change in prices | | | 9 | |
| | | | | |
| | | | 109 | |
| | | | | |
Net Increase in Direct and Government Aggregation Revenues | | | $ | 328 | |
| | | | | |
| | | |
| | | | Increase | |
| Source of Change in POLR Revenues | | | (Decrease) | |
| | | | (In millions) | |
| POLR: | | |
| Effect of decrease in sales volumes | | | $ | (384 | ) |
| Change in prices | | | 80 | |
| | | | | |
| | | | | (304 | ) |
| | | | | |
| | | |
| | | | Increase | |
Source of Change in Wholesale Revenues | | | | | (Decrease) | |
| | | (In millions) | | | (In millions) | |
| PLR: | | | | | |
Effect of 10.2% decrease in sales volumes | | $ | (91 | ) | |
| Wholesale: | | |
| Effect of increase in sales volumes | | | 12 | |
Change in prices | | | (125 | ) | | | (7 | ) |
| | | | (216 | ) | | | |
| Wholesale: | | | | | |
Effect of 76.3% decrease in sales volumes | | | (112 | ) | |
Change in prices | | | 10 | | |
| | | | (102 | ) | | 5 | |
| Net Decrease in Wholesale Revenues | | $ | (318 | ) | |
| | | | | |
Transmission revenues decreased $8increased $9 million due primarily due to higher MISO congestion revenues. The revenues derived from the inclusionsale of the transmission-related componentRECs declined $35 million in retail rates beginning in mid-2009 as a result of the CBP.
In the first three monthsquarter of 2010, FES sold $67 million of RECs.2011.
Expenses
Total operating expenses increased $312$81 million in the first three months of 2010,2011, compared with the same period of 2009.2010.
118
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2010, from2011, compared with the same period last year:
| | | | | |
| | | Increase | |
| Source of Change in Fuel and Purchased Power | | (Decrease) | |
| | | (In millions) | |
| Fossil Fuel: | | | | |
| Change due to decreased unit costs | | $ | (22 | ) |
| Change due to volume consumed | | | 31 | |
| | | | |
| | | | 9 | |
| | | | |
| Nuclear Fuel: | | | | |
| Change due to increased unit costs | | | 6 | |
| Change due to volume consumed | | | — | |
| | | | |
| | | | 6 | |
| | | | |
| Non-affiliated Purchased Power: | | | | |
| Change due to increased unit costs | | | 32 | |
| Change due to volume purchased | | | (185 | ) |
| | | | |
| | | | (153 | ) |
| | | | |
| Affiliated Purchased Power: | | | | |
| Change due to increased unit costs | | | 20 | |
| Change due to volume purchased | | | (12 | ) |
| | | | |
| | | | 8 | |
| | | | |
Net Decrease in Fuel and Purchased Power Costs | | $ | (130 | ) |
| | | | |
Source of Change in Fuel and Purchased Power | | | | |
| | | (In millions) | |
| Fossil Fuel: | | | | |
Change due to increased unit costs | | $ | 36 | |
Change due to volume consumed | | | (27 | ) |
| | | | 9 | |
| Nuclear Fuel: | | | | |
Change due to increased unit costs | | | 12 | |
Change due to volume consumed | | | 1 | |
| | | | 13 | |
| Non-affiliated Purchased Power: | | | | |
| Power contract mark-to-market adjustment | | | 52 | |
Change due to decreased unit costs | | | (62 | ) |
Change due to volume purchased | | | 300 | |
| | | | 290 | |
| Affiliated Purchased Power: | | | | |
Change due to increased unit costs | | | (12 | ) |
Change due to volume purchased | | | 10 | |
| | | | (2 | ) |
| Net Increase in Fuel and Purchased Power Costs | | $ | 310 | |
Fossil fuel costs increased $9 million in the first three months of 2010,2011, compared to the same period of 2009,2010, as a result of higher prices,generation at the fossil units, partially offset by reduced volume. The increased costs reflect higher coal transportation charges in the first three months of 2010, compared to the same period last year. Reduced volume reflects lower generation in the first three months of 2010, compared to the same period last year. Nuclear fuel costs increased $13 million,decreased fossil unit costs. Fossil unit prices declined primarily due to the replacement of nuclearimproved generating unit availability at more efficient units, partially offset by increased coal transportation costs. Nuclear fuel atexpenses increased primarily due to higher unit costsprices following the refueling outages that occurred in 2009.
2010.
Non-affiliated purchased power costs increased $290decreased $153 million due primarily to higherlower volumes purchased, and a power contract mark-to-market adjustment, partially offset by lowerhigher unit costs. The increasedecrease in volume primarily relates to the assumptionabsence in 2011 of a 1,300 MW third party contract fromassociated with serving Met-Ed and Penelec. $35 million of purchased power expense resulted from long positions in MISO that were unable to be netted with short positions in PJM, due to separate settlement requirements within each RTO.
Other operating expenses decreased $3increased $191 million in the first three months of 2010,2011, compared to the same period of 2009, primarily due to lower2010, as a result of increased RTO transmission costs ($111 million), an inventory valuation adjustment ($54 million) and increased nuclear operating costs ($2115 million), related to higher labor and related benefits, partially offset by increased transmission expenses ($7 million)lower professional and contractor costs.
In the first three month of 2011, impairment charges of long-lived assets increased expenses associated with uncollectible customer accounts and agent fees ($5 million).by $14 million.
Depreciation expenseGeneral taxes increased $2 million due to an increase in revenue-related taxes.
Other Expense
Total other expense decreased $9 million in the first three months of 2010,2011, compared to the same period of 20092010, primarily due to increased property additions.
General taxes increased $3 million due to sales taxes associated with increased revenues.
Other Expense
Total other expense decreased $12 million in the first three months of 2010, compared to the same period of 2009, primarily due to a $30 millionan increase in miscellaneous income ($16 million) and increased investment income resulting from reduced impairments in the value of nuclear decommissioning trust investments,($5 million), partially offset by a $17 millionan increase in interest expense (net of capitalized interest)interest — $12 million). InterestIncreased miscellaneous income was the result of mark-to-market adjustments on power related derivatives. Increased investment income was the result of higher nuclear decommissioning trust investment income. The increase in interest expense was the result of reduced capitalized interest associated with the completion of the Sammis AQC project in 2010 combined with increased primarily due to new issuances of long-term debt in the second half of 2009 combinedinterest expense associated with the restructuring of existing long-term debt.certain variable rate PCRBs into fixed rate modes.
119
OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
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 procure generation services for 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'sFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased to $36decreased by $6 million in the first three months of 2010,2011, compared to $12 million in the same period of 2009.2010. The increasedecrease primarily resulted from lower purchased power costsrevenues and higher other operating costs, partially offset by lower revenues.purchased power costs and amortization of regulatory assets.
Revenues
Revenues decreased $241$116 million, or 32.1%23%, in the first three months of 2010,2011, compared with the same period in 2009,2010, due primarily to a decrease in generation andrevenues, partially offset by higher distribution revenues.
Distribution revenues increased $10 million in the first three months of 2011, compared to the same period in 2010, primarily due to an increase in KWH deliveries and higher average prices in all customer classes. The higher KWH deliveries in the residential class were influenced by increased weather-related usage in the first three months of 2011, reflecting a 5% increase in heating degree days in OE’s service territory.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period in 2010, are summarized in the following tables:
| | | | |
| Distribution KWH Deliveries | | Increase | |
| | | | |
| Residential | | | 1.4 | % |
| Commercial | | | 1.2 | % |
| Industrial | | | 9.3 | % |
| | | |
Increase in Distribution Deliveries | | | 3.7 | % |
| | | |
| | | | | |
| Distribution Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 7 | |
| Commercial | | | 1 | |
| Industrial | | | 2 | |
| | | | |
Increase in Distribution Revenues | | $ | 10 | |
| | | | |
Retail generation revenues decreased $225$127 million primarily due to a decrease in KWH sales and lower average prices in all customer classes, partially offset by higher average pricesclasses. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. OE defers the difference between retail generation revenues and costs, resulting in the commercial and industrial classes.no material effect to current period earnings. Lower KWH sales in all customer classes were primarily the result of a 41.9% increase inincreased customer shopping, partially offset by increased weather-related usage in the first three months of 2010. Lower KWH sales to residential customers were also due to decreased weather-related usage, reflecting a 3.5% decrease in heating degree days in OE’s service territory. Higher average prices in the commercial and industrial classes, resulted from the CBP auction for the service period beginning June 1, 2009.2011, as described above.
120
Changes in retail generation KWH sales and revenues in the first three months of 2010, from2011, compared to the same period in 2009,2010, are summarized in the following tables:
| | | | |
| Retail Generation KWH Sales | | | Decrease | |
| | | | | |
| Residential | | | (28.133.0 | )% |
| Commercial | | | (57.243.2 | )% |
| Industrial | | | (65.416.3 | )% |
| | | |
Decrease in Retail Generation Sales | | | (45.632.0 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (85 | ) |
| Commercial | | | (30 | ) |
| Industrial | | | (12 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (127 | ) |
| | | | |
Expenses
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (78 | ) |
| Commercial | | | (80 | ) |
| Industrial | | | (67 | ) |
| Decrease in Retail Generation Revenues | | $ | (225 | ) |
Distribution revenuesTotal expenses decreased $7$108 million in the first three months of 2010,2011, compared to the same period in 2009, due to lower commercial and industrial revenues, partially offset by higher residential revenues. Commercial and industrial revenues were primarily impacted by lower average unit prices, resulting from lower transmission rates in 2010, partially offset by a PUCO-approved rate increase. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP, partially offset by lower KWH deliveries resulting from the warmer conditions described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (18%) and automotive customers (21%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, from the same period in 2009, are summarized in the following tables:
Distribution KWH Deliveries | | Increase
(Decrease)
| |
| | | | |
Residential | | | (2.2 | )% |
Commercial | | | (2.1 | )% |
Industrial | | | 3.4 | % |
Net Decrease in Distribution Deliveries | | | (0.6 | )% |
| Distribution Revenues | | Increase (Decrease) | |
| | | (In millions) |
| Residential | | $ | 7 | |
| Commercial | | | (3 | ) |
| Industrial | | | (11 | ) |
| Net Decrease in Distribution Revenues | | $ | (7 | ) |
Wholesale revenues decreased $6 million primarily due to lower unit prices, partially offset by an increase in sales to FES for OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Expenses
Total expenses decreased $283 million in the first three months of 2010, from the same period of 2009.2010. The following table presents changes from the prior period by expense category:
| Expenses – Changes | | Increase (Decrease) | | |
| | | | | | |
| | | | Increase | |
| Expenses — Changes | | | (Decrease) | |
| | | | (In millions) | | | (In millions) | |
| Purchased power costs | | $ | (222 | ) | | $ | (94 | ) |
| Other operating costs | | | (69 | ) | |
| Other operating expenses | | | 13 | |
| Amortization of regulatory assets, net | | | 9 | | | | (29 | ) |
| General taxes | | | (1 | ) | | 2 | |
| | | | | |
| Net Decrease in Expenses | | $ | (283 | ) | | $ | (108 | ) |
| | | | | |
Purchased power costs decreased in the first three months of 2010,2011, compared to the same period of 2009,2010, primarily due to lower KWH purchases resulting from increased customer shoppingreduced generation sales requirements in the first three months of 2010 and slightly2011 coupled with lower unit costs. The decreaseincrease in other operating costs for the first three months of 2010,2011 was primarily due to lower MISO transmission expenses (included in the cost of purchased power beginning June 1, 2009) and lower costs associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. Higherthe 2011 Beaver Valley Unit 2 refueling outage that were absent in 2010. The amortization of net regulatory assets wasdecreased primarily due to the recovery of PUCO-approved deferrals that beganhigher deferred residential generation credits in 2010.2011.
121
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
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'sFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings increasedavailable to $14parent decreased by $1 million in the first three months of 2010,2011, compared to a loss of $106 million in the same period of 2009.2010. The increasedecrease in earnings was primarily the due to decreased amortization of net regulatory assets,lower revenues, partially offset by lower purchased power and other operating costs, partially offset by decreased revenues and deferralamortization of new regulatory assets.
Revenues
Revenues decreased $120$105 million, or 26.6%32%, in the first three months of 2010,2011, compared to the same period of 2009,2010, due to decreasedlower retail generation and distribution revenues.
Retail generationDistribution revenues decreased $69$5 million in the first three months of 2010,2011, compared to the same period of 2009,2010, due to lower average unit prices for the industrial and residential customer classes offset by increased KWH deliveries across all sectors. The lower average unit prices were the result of the absence of transition charges in 2011. Higher KWH deliveries in the residential class were influenced by increased weather-related usage in the first three months of 2011, reflecting a 10% increase in heating degree days in CEI’s service territory.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| Distribution KWH Deliveries | | Increase | |
| | | | |
| Residential | | | 2.3 | % |
| Commercial | | | 3.1 | % |
| Industrial | | | 0.9 | % |
| | | |
Increase in Distribution Deliveries | | | 2.1 | % |
| | | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | — | |
| Commercial | | | 7 | |
| Industrial | | | (12 | ) |
| | | | |
Net Decrease in Distribution Revenues | | $ | (5 | ) |
| | | | |
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Retail generation revenues decreased $101 million in the first three months of 2011, compared to the same period of 2010, primarily due to lower KWH sales and lower average unit prices across all customer classes, partially offset by higher average unit pricesclasses. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. CEI defers the difference between retail generation revenues and costs, resulting in all customer classes.no material effect to current period earnings. Reduced KWH sales were primarily the result of increased customer shopping in the first three months of 2010.2011, partially offset by higher residential KWH deliveries resulting from the colder weather conditions. Lower KWH sales toaverage unit prices in the residential customers also resulted from decreased weather-related usage, reflecting a 9.2% decrease in heating degree days. Retail generation prices increased in 2010 as acustomer class were the result of the CBP auctiongeneration credits in place for the service period beginning June 1, 2009.
2011.
Changes in retail generation sales and revenues in the first three months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
| | | | |
| Retail Generation KWH Sales | | Decrease | |
| | | | | |
| Residential | | | (53.248.4 | )% |
| Commercial | | | (66.248.3 | )% |
| Industrial | | | (46.262.8 | )% |
Decrease in Retail Generation Sales | | | (53.6 | )% |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (17 | ) |
| Commercial | | | (33 | ) |
| Industrial | | | (19 | ) |
| Decrease in Retail Generation Revenues | | $ | (69 | ) |
Distribution revenues decreased $43 million in the first three months of 2010, compared to the same period of 2009, due to lower average unit prices for all customer classes and decreased KWH deliveries in the residential sector, partially offset by increased KWH deliveries in the industrial sector. The lower average unit prices were the result of lower transition rates in 2010, partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. Lower KWH sales in the residential sector were the result of the warmer weather described above. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (134%) and automotive customers (13%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | |
ResidentialDecrease in Retail Generation Sales | | | (3.953.3 | )% |
Commercial | | | (0.6 | )% |
Industrial | | | 10.9 | % |
Net Increase in Distribution Deliveries | | | 2.6 | % |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (46 | ) |
| Commercial | | | (29 | ) |
| Industrial | | | (26 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (101 | ) |
| | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (5 | ) |
| Commercial | | | (13 | ) |
| Industrial | | | (25 | ) |
| Decrease in Distribution Revenues | | $ | (43 | ) |
Expenses
Total expenses decreased $314$98 million in the first three months of 2010,2011, compared to the same period of 2009.2010. The following table presents the change from the prior period by expense category:
| Expenses - Changes | | Increase (Decrease) | | |
| | | | | | |
| | | | Increase | |
| Expenses — Changes | | | (Decrease) | |
| | | (In millions) | | | (In millions) | |
| Purchased power costs | | $ | (164 | ) | | $ | (82 | ) |
| Other operating costs | | | (33 | ) | | 4 | |
| Amortization of regulatory assets | | | (212 | ) | |
| Deferral of new regulatory assets | | | 95 | | |
| Amortization of regulatory assets, net | | | | (22 | ) |
| General taxes | | | 2 | |
| | | | | |
| Net Decrease in Expenses | | $ | (314 | ) | | $ | (98 | ) |
| | | | | |
Purchased power costs decreased in the first three months of 2010, primarily2011 due to lower KWH purchases resulting from reduced sales requirements as discussed above.in the first three months of 2011. Other operating costs decreasedexpenses increased due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), labor and employee benefit expenses and reduced regulatory obligations for economic development and energy efficiency programs.2011 inventory valuation adjustments. 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 contemporaneouscompletion of transition cost recovery at the end of 2010 and 2011 and deferred residential generation credits, partially offset by increased recovery of purchased power costsnon-residential distribution deferrals and the absence in 2010.2010 of deferred renewable energy credit expenses. General taxes increased in the first three months of 2011 due to increased property taxes in 2011.
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THE TOLEDO EDISON COMPANY
MANAGEMENT’S NARRATIVE
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 procures generation services for those customers electing to retain TE as their power supplier.
For additional information with respect to TE, please see the information contained in FirstEnergy'sFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Earnings available to parent increased to $8decreased by $2 million in the first three months of 2010,2011, compared to $1 million in the same period of 2009.2010. The increase wasdecrease primarily due to decreased net amortization of regulatory assets, purchased powerresulted from lower revenues and higher other operating costs, partially offset by a decrease in revenueslower purchased power costs and an increase in interest expense.deferral of regulatory assets.
Revenues
Revenues decreased $112$19 million, or 46%14%, in the first three months of 2010,2011, compared to the same period of 2009, primarily2010, due to lowera decrease in retail generation and distribution revenues, partially offset by an increase inhigher distribution revenues and wholesale generation revenues.
Retail generationDistribution revenues decreased $105increased $2 million in the first three months of 2010,2011, compared to the same period of 2009, primarily2010, due to higher residential and industrial revenues, partially offset by lower commercial revenues. Residential and industrial revenues were the result of higher average unit prices and higher KWH deliveries. The higher KWH deliveries in the residential class were influenced by increased weather-related usage in the first three months of 2011, reflecting a 9% increase in heating degree days in TE’s service territory. Commercial revenues were impacted by lower KWH deliveries and lower average unit prices.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
| Distribution KWH Deliveries | | (Decrease) | |
| | | | |
| Residential | | | 3.6 | % |
| Commercial | | | (2.3 | )% |
| Industrial | | | 5.3 | % |
| | | |
Net Increase in Distribution Deliveries | | | 3.3 | % |
| | | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 2 | |
| Commercial | | | (1 | ) |
| Industrial | | | 1 | |
| | | | |
Net Increase in Distribution Revenues | | $ | 2 | |
| | | | |
Retail generation revenues decreased $25 million in the first three months of 2011, compared to the same period of 2010, due to lower KWH sales acrossto all customer classes and lower unit prices to residential and industrial customers. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. TE defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Lower KWH sales to all customer classes were primarily due tothe result of increased customer shopping. Lower KWH sales for residential customers also resulted from decreasedshopping, partially offset by increased weather-related usage reflecting a 7.5% decrease in heating degree days in the first three months of 2010. Lower unit prices for industrial customers are primarily due to the absence of TE’s fuel cost recovery rider that was effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.2011, as described above.
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Changes in retail electric generation KWH sales and revenues in the first three months of 2010 from2011, compared to the same period of 20092010, are summarized in the following tables:
| | | | |
| Retail Generation KWH Sales | | Decrease | |
| | | | | |
| Residential | | | (47.928.5 | )% |
| Commercial | | | (69.849.5 | )% |
| Industrial | | | (57.713.1 | )% |
| | | | |
Decrease in Retail Generation Sales | | | (57.924.0 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (10 | ) |
| Commercial | | | (6 | ) |
| Industrial | | | (9 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (25 | ) |
| | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (24 | ) |
| Commercial | | | (35 | ) |
| Industrial | | | (46 | ) |
| Decrease in Retail Generation Revenues | | $ | (105 | ) |
DistributionWholesale revenues decreased $13increased $3 million in the first three months of 2010,2011, compared to the same period of 2009, primarily due to lower unit prices for all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices for all customer classes are primarily due to lower transmission rates. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major automotive customers (14%) and steel customers (37%).
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | |
Residential | | | (2.4 | )% |
Commercial | | | (2.6 | )% |
Industrial | | | 13.9 | % |
Net Increase in Distribution Deliveries | | | 4.7 | % |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (2 | ) |
| Commercial | | | (3 | ) |
| Industrial | | | (8 | ) |
| Decrease in Distribution Revenues | | $ | (13 | ) |
Wholesale revenue increased $4 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher revenues from associated sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased $131$15 million in the first three months of 2010,2011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
| Expenses – Changes | | Decrease | |
| | | (In millions) | |
| Purchased power costs | | $ | | ) |
Amortization (deferral) of regulatory assets, net | | | | |
| | | | |
| | | | |
| | | | ) |
| | | | | |
| | | Increase | |
| Expenses — Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (24 | ) |
| Other operating expenses | | | 11 | |
| Deferral of regulatory assets, net | | | (3 | ) |
| General Taxes | | | 1 | |
| | | | |
Net Decrease in Expenses | | $ | (15 | ) |
| | | | |
Purchased power costs decreased $93 million in the first three months of 2010,2011, compared to the same period of 20092010, due to lower volume as a resultKWH purchases resulting from reduced generation sales requirements in the first three months of decreased KWH sales requirements.2011 coupled with lower unit costs. The $18 million decreaseincrease in amortization (deferral)other operating costs for the first three months of net regulatory assets2011 was primarily due to an increaseexpenses associated with the 2011 Beaver Valley Unit 2 refueling outage that were absent in PUCO-approved cost deferrals, lower MISO transmission cost amortization, partially offset by the absence2010 and higher storm restoration expenses. The deferral of MISO transmission and fuelregulatory assets increased due to higher PUCO-approved cost deferrals in the first three months of 2010,2011, compared to the same period of 2009. Other operating costs decreased $19 million primarily due to reduced transmission expense (included in the cost of power purchased from others beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor and employee benefit expenses. The decrease in general taxes was primarily due to lower Ohio KWH taxes as a result of the reduced KWH deliveries discussed above.2010.
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Other Expense
Other expense increased $7 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher interest expense associated with the April 2009 issuance of $300 million senior secured notes.
JERSEY CENTRAL POWER & LIGHT COMPANY
MANAGEMENT’S NARRATIVE
MANAGEMENT'S NARRATIVE
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 above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees andMarket Risk Information, Credit Risk, Outlook, Regulatory Matters, Environmental Matters, Other Assurances, Outlook, Market RiskLegal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased to $29decreased by $10 million in the first three months of 2010,2011, compared to $28 million in the same period of 2009.2010. The increasedecrease was primarily due to lower purchased power costsrevenues and decreasedincreased net amortization of regulatory assets, partially offset by lower revenuespurchased power costs and increased other operating costs.
Revenues
In the first three months of 2010,2011, revenues decreased $70$57 million, or 9%8%, compared to the same period of 2009.2010. The decrease in revenues iswas primarily due to a decreaselower distribution and retail generation revenues, partially offset by an increase in retail and wholesale generation revenues and distribution throughputother revenues.
InDistribution revenues decreased $17 million in the first three months of 2011, compared to the same period of 2010, retailprimarily due to a NJBPU-approved rate adjustment which became effective March 1, 2011 for all customer classes, partially offset by higher KWH deliveries in the residential class resulting from a 6% increase in heating degree days.
Changes in distribution KWH deliveries and revenues in the first three months of 2011 compared to the same period of 2010 are summarized in the following tables:
| | | | |
| | Increase | |
| Distribution KWH Deliveries | | (Decrease) | |
| | | | |
| Residential | | | 1.4 | % |
| Commercial | | | (3.4 | )% |
| Industrial | | | (2.0 | )% |
| | | |
Net Decrease in Distribution Deliveries | | | (1.1 | )% |
| | | |
| | | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (5 | ) |
| Commercial | | | (10 | ) |
| Industrial | | | (2 | ) |
| | | | |
Decrease in Distribution Revenues | | $ | (17 | ) |
| | | | |
Retail generation revenues decreased $56$47 million due to lower retail generation KWH sales in all sectors, partially offset by higher unit pricescustomer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and costs, resulting in the residential and commercial sectors. Lowerno material effect to current period earnings. These lower sales to the commercial and industrial sector were primarily due to an increase in the number of shopping customers. Lower KWH sales to the residential sector reflected decreased weather-related usage due to an 8.7% decrease in heating degree days in the first three months of 2010 compared to the same period of 2009.customer shopping.
126
Changes in retail generation KWH sales and revenues by customer class in the first three months of 20102011, compared to the same period of 20092010, are summarized in the following tables:
| | | | |
| Retail Generation KWH Sales | | Decrease | |
| | | | | |
| Residential | | | (1.57.5 | )% |
| Commercial | | | (36.026.4 | )% |
| Industrial | | | (25.723.1 | )% |
| | | |
Decrease in Retail Generation Sales | | | (16.013.7 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (15 | ) |
| Commercial | | | (29 | ) |
| Industrial | | | (3 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (47 | ) |
| | | | |
| Retail Generation Revenues | | Increase (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | (55 | ) |
| Industrial | | | (4 | ) |
| Net Decrease in Generation Revenues | | $ | (56 | ) |
Wholesale generation revenues decreased $11increased $3 million in the first three months of 20102011, compared to the same period of 20092010, due primarily to a decreasean increase in sales volume resulting from reduced available power for sale due to the termination of a NUG power purchase contract in July 2009.volumes.
DistributionOther revenues decreased $5increased $4 million in the first three months of 20102011, compared to the same period of 20092010, primarily due to loweran increase in transition bond revenues as a result of higher KWH deliveries reflecting milder weather in JCP&L’s service territory, and a decrease in composite unit prices in the commercial and industrial sectors.
to residential customers.
Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:
Distribution KWH Deliveries | | Increase
(Decrease)
| |
| | | | | |
Residential | | | | (1.5 | )% |
Commercial | | | | (1.6 | )% |
Industrial | | | | 1.3 | % |
Net Decrease in Distribution Deliveries | | | | (1.2 | )% |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (2 | ) |
| Commercial | | | (3 | ) |
| Industrial | | | - | |
| Decrease in Distribution Revenues | | $ | (5 | ) |
Expenses
Total expenses decreased $73$43 million in the first three months of 20102011, compared to the same period of 2009.2010. The following table presents changes from the prior period by expense category:
| Expenses - Changes | | Increase (Decrease) | | |
| | | | | | |
| | | | Increase | |
| Expenses — Changes | | | (Decrease) | |
| | | (In millions) | | | (In millions) | |
| Purchased power costs | | $ | (67 | ) | | $ | (44 | ) |
| Other operating costs | | | 9 | | | | (9 | ) |
| Provision for depreciation | | | 3 | | | | (3 | ) |
| Amortization of regulatory assets, net | | | (17 | ) | | 12 | |
| General taxes | | | (1 | ) | | 1 | |
| | | | | |
| Net Decrease in Expenses | | $ | (73 | ) | | $ | (43 | ) |
| | | | | |
Purchased power costs decreased in the first three months of 20102011 primarily due to the lower KWH sales requirements and termination of a NUG contract as discussed above.from reduced sales. Other operating costs increased in the first three months of 2010 primarily due to higher labor and tree trimming expenses related to major storms in JCP&L’s service territory. Depreciation expense increased due to an increase in depreciable property since the first quarter of 2009. Amortization of regulatory assets decreased in the first three months of 20102011 primarily due to deferrallower storm restoration costs, partially offset by inventory valuation adjustments. The amortization of the major storm costs. General taxes decreased principallyregulatory assets increased primarily due to taxes assessed on a lower revenue base.storm cost deferrals and the write-off of nonrecoverable NUG costs, partially offset by lower purchased power deferrals in the first quarter of 2011.
127
METROPOLITAN EDISON COMPANY
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. In 2011, Met-Ed has a partialprocures power under its Default Service Plan (DSP) in which full requirements wholesale power sales agreement with FES, to supply nearly allproducts (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 118,595 shares of its energy requirements at fixed prices through 2010.
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'sFirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations aboveunder the following subheadings, which information is incorporated by reference herein: Market Risk Information, Credit Risk, Outlook, Capital Resources and Liquidity, Regulatory Matters, Environmental Matters, Other Legal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $10 million in the first three months of 2011, compared to the same period of 2010. The increase was primarily due to decreased purchased power, other operating expenses and amortization of net regulatory assets, partially offset by decreased revenues.
Revenues
Revenue decreased $116 million, or 24%, in the first three months of 2011 compared to the same period of 2010, reflecting lower distribution, wholesale generation and transmission revenues, partially offset by an increase in retail generation revenues.
Distribution revenues decreased $72 million in the first three months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rate. Higher KWH deliveries to industrial customers were due to improving economic conditions in Met-Ed’s service territory. Higher residential and commercial KWH deliveries reflect increased weather-related usage due to an 8% increase in heating degree days in the first three months of 2011, compared to the same period in 2010.
Changes in distribution KWH deliveries and revenues in the first three months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| Distribution KWH Deliveries | | Increase | |
| | | | |
| Residential | | | 3.4 | % |
| Commercial | | | 2.5 | % |
| Industrial | | | 5.8 | % |
| | | |
Increase in Distribution Deliveries | | | 4.1 | % |
| | | |
| | | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (29 | ) |
| Commercial | | | (17 | ) |
| Industrial | | | (26 | ) |
| | | | |
Decrease in Distribution Revenues | | $ | (72 | ) |
| | | | |
Retail generation revenues increased $18 million in the first three months of 2011 compared to the same period of 2010, due to an increase in generation rates from the auctions and now including transmission services in the rates under the DSP effective January 1, 2011. The DSP resulted in higher composite unit prices across all customer classes. Higher KWH sales to residential customers were primarily due to weather-related usage as described above. Increased customer shopping in the commercial and industrial classes of 36% and 81%, respectively, reduced KWH sales to these classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. Met-Ed defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings.
128
Changes in retail generation KWH sales and revenues in the first three months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
| Retail Generation KWH Sales | | (Decrease) | |
| | | | |
| Residential | | | 2.7 | % |
| Commercial | | | (34.1 | )% |
| Industrial | | | (80.0 | )% |
| | | |
Net Decrease in Retail Generation Sales | | | (34.5 | )% |
| | | |
| | | | | |
| | | Increase | |
| Retail Generation Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 53 | |
| Commercial | | | 3 | |
| Industrial | | | (38 | ) |
| | | | |
Net Increase in Retail Generation Revenues | | $ | 18 | |
| | | | |
Wholesale revenues decreased $54 million in the first three months of 2011 compared to the same period of 2010, primarily due to Met-Ed ending certain capacity purchase for resale contracts.
Transmission revenues decreased $8 million in the first three months of 2011 compared to the same period of 2010 primarily due to decreased FTR 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 decreased $121 million in the first three months of 2011 compared to the same period of 2010. The following table presents changes from the prior year by expense category:
| | | | | |
| Expenses — Changes | | Decrease | |
| | | (In millions) | |
| Purchased power costs | | $ | (50 | ) |
| Other operating costs | | | (54 | ) |
| Amortization of regulatory assets, net | | | (17 | ) |
| | | | |
Decrease in Expenses | | $ | (121 | ) |
| | | | |
Purchased power costs decreased $50 million in the first three months of 2011 due to a decrease in KWH purchased to source generation sales requirements, partially offset by higher unit costs. Other operating costs decreased $54 million in the first three months of 2011 compared to the same period in 2010 primarily due to lower transmission congestion and transmission loss expenses (see reference to deferral accounting above). The amortization of regulatory assets decreased $17 million in the first three months of 2011 primarily due to the termination of transmission and transition tariff riders at the end of 2010.
Other Expense
In the first three months of 2011, interest income decreased due to reduced CTC stranded asset balances compared to the same period of 2010.
129
PENNSYLVANIA ELECTRIC COMPANY
MANAGEMENT’S NARRATIVE
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 service for those customers electing to retain Penelec as their power supplier. Beginning in 2011, Penelec procures power under its Default Service Plan (DSP) in which full requirements products (energy, capacity, ancillary services, and 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: Capital Resources and Liquidity, Guarantees andMarket Risk Information, Credit Risk, Outlook, Regulatory Matters, Environmental Matters, Other Assurances, Outlook, Market RiskLegal Proceedings and New Accounting Standards and Interpretations.
Results of Operations
Net income increased slightly in the first three months of 2011, compared to the same period of 2010. The increase was primarily due to lower purchased power and other operating costs, partially offset by lower revenues, net amortization of regulatory assets and higher general taxes.
Revenues
Revenue decreased $79 million, or 19.5%, in the first three months of 2011 compared to $12the same period of 2010. The decrease in revenue was primarily due to lower retail and wholesale generation revenues and lower transmission revenues, partially offset by higher distribution revenues.
Distribution revenues increased by $1 million in the first three months of 2010, compared to $17 million in the same period of 2009. The decrease was primarily due to increased purchased power costs and amortization of net regulatory assets, partially offset by an increase in distribution and generation revenues.
Revenues
Revenues increased by $43 million, or 10%, in the first three months of 20102011, compared to the same period of 20092010, primarily due to higher distributionan increase in the retail transition rates and generation revenues,energy efficiency rates for all customer classes, partially offset by a decrease in transmission revenues.
Distribution revenues increased $24 milliondecreased KWH sales in the first three months of 2010, compared to the same period of 2009, primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009, partially offset by lower CTC rates for the residential class resulting from a PPUC-approved NUG Statement Compliance filing. Lower KWH deliveries to residential customers reflect reduced weather-related usage due to a 7.3% decrease in heating degree days in the first three months of 2010, compared to the same period of 2009. Higher industrial KWH deliveries were due to the recovering economy.
and commercial classes.
Changes in distribution KWH deliveries and revenues in the first three months of 20102011, compared to the same period of 20092010, are summarized in the following tables:
| | | | |
| | | Increase | |
| Distribution KWH Deliveries | | (Decrease) | |
| | | | | |
| Residential | | | (5.40.2 | )% |
| Commercial | | | (1.93.0 | )% |
| Industrial | | | 2.410.0 | % |
Net Decrease in Distribution Deliveries | | | (2.5 | )% |
Distribution Revenues | | Increase | |
| | | (In millions) | |
Residential | | $ | 7 | |
CommercialNet Increase in Distribution Deliveries | | | 103.1 | % |
Industrial | | | 7 | |
Increase in Distribution Revenues | | $ | 24 | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | (5 | ) |
| Industrial | | | 3 | |
| | | | |
Net Increase in Distribution Revenues | | $ | 1 | |
| | | | |
WholesaleRetail generation revenues increaseddecreased $22 million in the first three months of 20102011, compared to the same period of 2009,2010, primarily reflecting higher PJM spot market prices.
Retail generation revenues increased $3 million in the first three months of 2010, compareddue to the same period of 2009, due primarily to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to the industrial customer class. This increase was partially offset by lower KWH sales to the residential and commercialall customer classes, partially offset by higher generation rates for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. Penelec defers the difference between retail generation revenues and costs, resulting in no material effect to current period earnings. Lower sales to all customer classes were primarily due to an increase in customer shopping following the expiration of generation rate caps at the end of 2010. Higher generation rates reflect the inclusion of transmission services in generation rates under the DSP, effective January 1, 2011.
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Changes in retail generation KWH sales and revenues in the first three months of 2010,2011, compared to the same period of 2009,2010, are summarized in the following tables:
| | | Increase | | |
| Retail Generation KWH Sales | | (Decrease)Decrease | |
| | | | | |
Residential | | | (5.4 | )% |
Commercial | | | (1.9 | )% |
Industrial | | | 2.4 | % |
Net Decrease in Retail Generation Sales | | | (2.5 | )% |
| | Increase | |
Retail Generation Revenues | | (Decrease) | |
| | (In millions) | |
Residential | | $ | 3 | |
Commercial | | | (1 | ) |
Industrial | | | 1 | |
Net Increase in Retail Generation Revenues | | $ | 3 | |
Transmission revenues decreased $6 million in the first three months of 2010 compared to the same period of 2009 primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total operating expenses increased $46 million in the first three months of 2010 compared to the same period of 2009. The following table presents changes from the prior year by expense category:
| Expenses – Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 29 | |
| Other operating costs | | | (4 | ) |
| Amortization of regulatory assets, net | | | 21 | |
| Net Increase in Expenses | | $ | 46 | |
Purchased power costs increased $29 million in the first three months of 2010 due to an increase in unit costs, partially offset by reduced volumes purchased as a result of lower KWH sales requirements. The net amortization of regulatory assets increased $21 million in the first three months of 2010 compared to the same period of 2009 primarily due to increased transmission cost recovery. Other operating costs decreased $4 million in the first three months of 2010 primarily due to lower employee benefit expenses.
Other Expense
Other expense increased in the first three months of 2010 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base.
PENNSYLVANIA ELECTRIC COMPANY
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 has a partial requirements wholesale power sales agreement with FES, to supply nearly all of its energy requirements at fixed prices through 2010.
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 above the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income decreased to $17 million in the first three months of 2010, compared to $19 million in the same period of 2009. The decrease was primarily due to higher purchased power costs, partially offset by higher revenues and decreases in the amortization (deferral) of net regulatory assets, other operating costs and general taxes.
Revenues
In the first three months of 2010, revenues increased $15 million, or 4%, compared to the same period of 2009. The increase in revenue is primarily due to higher wholesale and retail generation revenues, partially offset by lower distribution and transmission revenues.
Wholesale revenues increased $18 million in the first three months of 2010, compared to the same period of 2009, primarily reflecting higher PJM capacity prices.
Retail generation revenues increased $16 million in the first three months of 2010, compared to the same period of 2009, primarily due to higher unit prices in all customer classes and higher KWH sales to the commercial and industrial customer classes, partially offset by decreased KWH sales to the residential customer class. Higher unit prices across all customer classes are primarily due to an increase in the generation rate resulting from the PPUC-approved NUG Statement Compliance filing, effective January 1, 2010. Higher KWH sales to commercial and industrial customers are due to improving economic conditions in Penelec’s service territory. Lower KWH sales to residential customers are due to decreased weather-related usage, reflecting a 6.1% decrease in heating degree day s in the first three months of 2010.
Changes in retail generation sales and revenues in the first three months of 2010 compared to the same period of 2009 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | |
| | | | |
| Residential | | | (1.10.4 | )% |
| Commercial | | | 0.7(38.3 | )% |
| Industrial | | | 3.1(78.5 | )% |
Net increase in Retail Generation Sales | | | 0.6 | % |
| | | | |
| Retail Generation Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | 6 | |
| Industrial | | | 7 | |
| Increase in Retail Generation Revenues | | $ | 16 | |
Distribution revenues decreased by $11 million in the first three months of 2010, compared to the same period of 2009, primarily due to a decrease in the transition rate in all customer classes resulting from the PPUC-approved NUG Statement Compliance filing, partially offset by an increase in the universal service rate for the residential customer class.
Changes in distribution KWH deliveries and revenues in the first three months of 2010, compared to the same period of 2009, are summarized in the following tables:
Distribution KWH Deliveries | | Increase (Decrease) | |
| | | | |
ResidentialDecrease in Retail Generation Sales | | | (1.139.1 | )% |
Commercial | | | 0.7 | % |
Industrial | | | 3.8 | % |
Net increase in Distribution Deliveries | | | 0.9 | % |
| | | | | |
| | | Increase | |
| Retail Generation Revenues | | (Decrease) | |
| | | (In millions) | �� |
| Residential | | $ | 31 | |
| Commercial | | | (9 | ) |
| Industrial | | | (44 | ) |
| | | | |
Net Decrease in Retail Generation Revenues | | $ | (22 | ) |
| | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (1 | ) |
| Commercial | | | (6 | ) |
| Industrial | | | (4 | ) |
| Decrease in Distribution Revenues | | $ | (11 | ) |
TransmissionWholesale generation revenues decreased by $4$49 million in the first three months of 2010,2011, compared to the same period of 2009,2010, due to Penelec no longer purchasing non-NUG capacity for resale to the PJM market beginning in 2011.
Transmission revenues decreased $8 million in the first three months of 2011, compared to the same period of 2010, primarily due to lower revenues related to Penelec’s Financial Transmission Rights.Rights revenues. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Expenses
Total operating expenses increaseddecreased by $9$75 million in the first three months of 2010,2011, as compared with the same period of 2009.2010. The following table presents changes from the prior periodyear by expense category:
| | | | | |
| | | Increase | |
| Expenses — Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (71 | ) |
| Other operating costs | | | (31 | ) |
| Amortization of regulatory assets, net | | | 23 | |
| General taxes | | | 4 | |
| | | | |
Net Decrease in Expenses | | $ | (75 | ) |
| | | | |
| Expenses - Changes | | Increase (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | 37 | |
| Amortization (deferral) of regulatory assets, net | | | (19 | ) |
| Other operating costs | | | (5 | ) |
| General taxes | | | (4 | ) |
| Net Increase in Expenses | | $ | 9 | |
Purchased power costs increased $37decreased $71 million in the first three months of 2010,2011, compared to the same period of 2009,2010, primarily due to higher unit costs. The amortization (deferral) of net regulatory assets decreased $19KWH purchased to source generation sales requirements. Other operating costs decreased $31 million in the first three months of 2010,2011, primarily due to increased cost deferrals resulting from higherlower transmission congestion and transmission loss expenses and decreased(see reference to deferral accounting above). The amortization of net regulatory assets resulting from lower CTC revenues. Other operating costs decreased $5increased $23 million in the first three months of 2010,2011, primarily due to reduced labor and employee benefit expenses.NUG deferrals as a result of a NUG Rider implemented in January 2011. General taxes decreasedincreased $4 million primarily due to higher Pennsylvania Sales and Use Taxes and the absence of a favorable ruling on a property tax appeal.
Other Expense
Inappeal in the first three monthsquarter of 2010, other expense increased $3 million primarily due to an increase in interest expense on long-term debt, partially offset by lower interest expense on short-term borrowings.2010.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
| | |
| ITEM 3. | | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See "Management's“Management’s Discussion and Analysis of Financial Condition and Results of Operations –— Market Risk Information"Information” in Item 2 above.
ITEM 4. | | |
| ITEM 4. | | CONTROLS AND PROCEDURES |
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES –— FIRSTENERGY
FirstEnergy'sFirstEnergy’s management, with the participation of its chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of the registrant'sregistrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer have concluded that the registrant'sregistrant’s disclosure controls and procedures were effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
CONTROL OVER FINANCIAL REPORTING
During the quarter ended March 31, 2010,2011, other than changes resulting from the Allegheny merger discussed below, there werehave been no changes in FirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant'sFirstEnergy’s internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant's management, withOn February 25, 2011, the participation of its chief executive officermerger between FirstEnergy and chief financial officer, have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures, as definedAllegheny closed. FirstEnergy is currently in the Securities Exchange Actprocess of 1934,integrating Allegheny’s operations, processes, and internal controls. See Note 2 to the consolidated financial statements in Part I, Item I for additional information relating to the merger.
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PART II. OTHER INFORMATION
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV, now known as amended, Rules 13a-15(e)Wolf Mining Company, entered into a long term Coal Sales Agreement with AE Supply and 15(d)-15(e)MP for the supply of coal to the Harrison generating facility. Anker Coal, now known as Hunter Ridge Holdings Inc., guaranteed performance under the contract. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held on January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred damages for replacement coal purchased through the end of the period covered by this report. Based on2010 and will incur additional damages for future shortfalls. The total damages claimed were in excess of $150 million. Defendants primarily claim that evaluation, each registrant’s chief executive officer and chief financial officer have concluded that such registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31, 2010, there were no changestheir performance is excused under a force majeure clause in the registrants' internal control over financial reportingcoal sales agreement and presented evidence at trial that has materially affected, or is reasonably likelythey will continue to materially affect,not provide the registrants' internal control over financial reporting.contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million, which may be challenged in post-trial filings and an appeal.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Additional Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 810 and 911 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
FirstEnergy'sFirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2009,2010, includes a detailed discussion of its risk factors. There have been no material changes to theseIn connection with the recent acquisition of Allegheny and the current events in Japan, the information presented below updates and supplements the risk factors appearing in our annual Report on Form 10-K for the quarteryear ended MarchDecember 31, 2010.
Potential NRC Regulation in Response to the Incident at Japan’s Fukushima Daiichi Nuclear Plant
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDSAs a result of the NRC’s investigation of the incident at the Fukushima Daiichi nuclear plant, potential exists for the NRC to promulgate new or revised requirements with respect to nuclear plants located in the United States, which could necessitate additional expenditures at our nuclear plants. It is also possible that the NRC could suspend or otherwise delay pending nuclear relicensing proceedings, including the Davis-Besse relicensing proceeding. FirstEnergy cannot currently estimate the impact of any such regulatory actions on its financial condition or results of operations.
Risks Associated With Our Recently Completed Merger
Our Merger with AE May Not Achieve Its Intended Results.
We entered into the merger agreement with AE with the expectation that the merger would result in various benefits, including, among other things, cost savings and operating efficiencies relating to the regulated segments and the unregulated competitive segment. Our ability to achieve 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 and maintenance of the current credit ratings of the combined company and its subsidiaries. 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.
As a Result of the Merger We Will be Subject to Business Uncertainties That Could Adversely Affect Our Financial Results.
Although we are taking steps designed to reduce any adverse effects, uncertainty about the effect of the merger with AE on employees and customers may have an adverse effect on us. Employee retention and recruitment may be particularly challenging, as employees and prospective employees may experience uncertainty about their future roles with the combined company. Despite our retention and recruiting efforts, key employees may 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. Additionally, customers, suppliers and others that deal with us may seek to change existing relationships.
Furthermore, 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 each case, our business results could be affected.
133
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
The combined company’s generation fleet has a higher percentage of coal-fired generation capacity compared to FirstEnergy’s previous generation mix. As a result, FirstEnergy’s exposure to new or changing legislation, regulation or other legal requirements related to greenhouse gas or other emissions may be increased compared to its previous exposure. Approximately 52% of FirstEnergy’s pre-merger generation fleet capacity was coal-fired, with the remainder being low-emitting natural gas, oil fired or non-emitting nuclear and pumped storage. Approximately 78% of Allegheny’s generation fleet capacity is coal-fired. Approximately 62% of the combined company’s fleet capacity is coal-fired. Historically, coal-fired generating plants face greater exposure to the costs of complying with federal, state and local environmental statutes, rules and regulations relating to emissions of substances such as sulfur dioxide, nitrogen oxide and mercury. In addition, there are currently a number of federal, state and international initiatives under consideration to, among other things, require reductions in greenhouse gas emissions from power generation or other facilities and to regulate coal combustion by-products, such as coal ash, as hazardous waste. These legal requirements and initiatives could require substantial additional costs, extensive mitigation efforts and, in the case of greenhouse gas legislation, could raise uncertainty about the future viability of fossil fuels as an energy source for new and existing electric generation facilities. Failure to comply with any such existing or future legal requirements may also result in the assessment of fines and penalties. Significant resources also may be expended to defend against allegations of violations of any such requirements. FirstEnergy expects approximately 70% of its generation fleet to be non-emitting or low-emitting by the end of 2011. All of Allegheny’s supercritical coal-fired generation assets are scrubbed, and its generation portfolio also includes pumped storage and natural gas generation capacity. The combined company’s generation fleet nevertheless could face greater exposure to risks relating to the foregoing legal requirements than FirstEnergy’s pre-merger fleet due to the combined company’s increased percentage of coal-fired generation facilities.
| | |
| ITEM 2. | | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS |
(c) FirstEnergy
The table below includes information on a monthly basis regarding purchases made by FirstEnergy of its common stock during the first quarter of 2010.2011.
| | | | | | | | | | | | | | | | | |
| | | Period | |
| | | January | | | February | | | March | | | First Quarter | |
| | | | | | | | | | | | | | | | | |
Total Number of Shares Purchased(a) | | | 32,053 | | | | 543,138 | | | | 1,344,212 | | | | 1,919,403 | |
| | | | | | | | | | | | | | | | | |
| Average Price Paid per Share | | $ | 38.36 | | | $ | 38.44 | | | $ | 37.55 | | | $ | 37.81 | |
| | | | | | | | | | | | | | | | | |
| 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 | | | — | | | | — | | | | — | | | | — | |
| | | Period | |
| | | January | | February | | March | | First Quarter | |
Total Number of Shares Purchased (a) | | 64,186 | | 188,695 | | 1,184,918 | | 1,437,799 | |
| Average Price Paid per Share | | $45.35 | | $39.56 | | $39.06 | | $39.41 | |
| Total Number of Shares Purchased | | | | | | | | | |
As Part of Publicly Announced Plans | | | | | | | | | |
| | | | | | | | | |
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 commonstock 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 De ferred Compensation Plan. | |
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
Exhibit
Number
| | |
| (a) | | Share amounts reflect purchases on the open market to satisfy FirstEnergy’s obligations to deliver common stock for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan. |
134
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. On March 16, 2011, Signal Peak Mine received a letter from MSHA indicating that the mine is no longer being considered for a pattern of potential violations notice.
Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended March 31, 2011:
| | | | | |
| | | Signal | |
| | | Peak | |
| Number of significant and substantial violations of mandatory health or safety standards under 104* | | | 22 | |
| 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)* | | | — | |
| 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 | | | — | |
| Pending Mine Safety Commission legal actions (including any contested citations issued) | | | 13 | |
| Number of mining related fatalities | | | — | |
| Total dollar value of proposed assessments | | $ | 1,892 | |
| | |
| * | | References to sections under 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.
135
Exhibit Number
| | | | | | |
|
| FirstEnergy | | | | | | |
| | | |
FirstEnergy
3.1 | |
| | 2.1 | Agreement and PlanAmendment to the Amended Articles of Merger,Incorporation of FirstEnergy Corp. dated as of February 10, 2010, by and among FirstEnergy Corp., Element Merger Sub, Inc. and Allegheny Energy, Inc.25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 11, 2010,25, 2011, Exhibit 2.1,3.1, File No. 333-21011)21011) |
| | | | | | | |
| | | 10.1 | | | Allegheny Energy, Inc. 1998 Long-Term Incentive Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.2, File No. 21011) |
| | | | | | |
| | | 10.2 | | | Allegheny Energy, Inc. 2008 Long-Term Incentive Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.3, File No. 21011) |
| | | | | | |
| | | 10.3 | | | Allegheny Energy, Inc. Non-Employee Director Stock Plan (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.4, File No. 21011) |
| | | | | | |
| | | 10.4 | | | Allegheny Energy, Inc. Amended and Restated Revised Plan for Deferral of Compensation of directors (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 10.5, File No. 21011) |
| | | | | | |
| | | 10.5 | | | Amendment to FirstEnergy Corp. 2007 Incentive Compensation Plan, effective January 1, 2011 |
| | | | | | |
| | | 10.6 | | | Amendment to FirstEnergy Corp. Executive Deferred Compensation Plan, effective January 1, 2012 |
| | | | | | |
| | | 10.7 | | | Amendment to FirstEnergy Corp. Deferred Compensation Plan for Outside Directors, effective January 1, 2012 |
| | | | | | |
| | | 10.8 | | | Amendment to FirstEnergy Corp. Supplemental Executive Retirement Plan, effective January 1, 2012 |
| | | | | | |
| | | 10.9 | | | FirstEnergy Corp. Change in Control Severance Plan |
| | | | | | |
| | | 10.10 | | | Amendment to Employment Agreement, dated February 25, 2011, between FirstEnergy Service Company and Gary R. Leidich |
| | | | | | |
| | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | 101* | | | | | |
| | | 101 | * | | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2010,2011, formatted in XBRL (eXtensible(extensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information. |
| | | 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. | | | | |
FES | | | | | | |
| | | | 10.1 | | | Asset Purchase Agreement dated as of March 11, 2011 by and between FirstEnergy Generation Corp. and American Municipal Power, Inc. |
| | | | | | |
| | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
OE | | | | | | |
| | | | | | | |
| | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
CEI | | | | | | |
| | | | | | | |
| | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | | |
| TE | | | | | | |
| | | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | | |
136
| | | | | | |
|
| JCP&L | | | | | | |
| | | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | | |
| Met-Ed | | | | | | |
| | | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | | |
| Penelec | | | | | | |
| | | | 12 | | | Fixed charge ratios |
| | | | | | | |
| | | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | | | | |
| | | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
| | |
| * | | Users of these data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of these data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections. |
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
137
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 4, 2010
3, 2011
| | FIRSTENERGY CORP. |
| | Registrant | |
|
| | |
| FIRSTENERGY SOLUTIONS CORP. |
| Registrant |
| |
| OHIO EDISON COMPANY |
| Registrant |
| |
| THE CLEVELAND ELECTRIC |
| ILLUMINATING COMPANY |
| Registrant |
| |
| THE TOLEDO EDISON COMPANY |
| Registrant |
| |
| METROPOLITAN EDISON COMPANY |
| Registrant |
| |
| PENNSYLVANIA ELECTRIC COMPANY |
| Registrant |
| |
| Harvey L. Wagner |
| Vice President, Controller |
| and Chief Accounting Officer |
| JERSEY CENTRAL POWER & LIGHT COMPANY |
| Registrant |
| | |
| | |
| | |
| | | FIRSTENERGY SOLUTIONS CORP.Registrant | | |
| | Kevin R. Burgess | | | |
| | Controller | OHIO EDISON COMPANYRegistrant | | |
| | | | |
| | THE CLEVELAND ELECTRIC ILLUMINATING COMPANYRegistrant | | |
| | | | |
| | THE TOLEDO EDISON COMPANYRegistrant | | |
| | | | |
| | METROPOLITAN EDISON COMPANYRegistrant | | |
| | | | |
| | PENNSYLVANIA ELECTRIC COMPANYRegistrant | | |
| | | | |
| | /s/ Harvey L. WagnerHarvey L. Wagner | | |
| | Vice President, Controller | | |
| | and Chief Accounting Officer | | |
| | | | |
| | JERSEY CENTRAL POWER & LIGHT COMPANYRegistrant | | |
| | | | |
| | /s/ K. Jon TaylorK. Jon Taylor | | |
| | Controller | | |
| | (Principal Accounting Officer) | | |