UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D. C.D.C. 20549
FORM 10-Q
(Mark One)
þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 20112012
OR
o¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ___________________ to ___________________ |
| | | | |
| Commission | | Registrant; State of Incorporation; | | I.R.S. Employer |
| File Number | | Address; and Telephone Number | | Identification No. |
| | | | | |
| 333-21011 | | FIRSTENERGY CORP. | | 34-1843785 |
| | | (An Ohio Corporation) | | |
| | | 76 South Main Street | | |
| | | Akron, OH 44308 | | |
| | | Telephone (800)736-3402 | | |
| | | | | |
| 000-53742 | | FIRSTENERGY SOLUTIONS CORP. | | 31-1560186 |
| | | (An Ohio Corporation) | | |
| | | c/o FirstEnergy Corp. | | |
| | | 76 South Main Street | | |
| | | Akron, OH 44308 | | |
| | | Telephone (800)736-3402 | | |
| | | | | |
| 1-2578 | | OHIO EDISON COMPANY | | 34-0437786 |
| | | (An Ohio Corporation) | | |
| | | c/o FirstEnergy Corp. | | |
| | | 76 South Main Street | | |
| | | Akron, OH 44308 | | |
| | | Telephone (800)736-3402 | | |
| | | | |
1-2323 | | THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
| | 34-0150020 |
| | (An Ohio Corporation) | | |
| | c/o FirstEnergy Corp. | | |
| | 76 South Main Street | | |
| | Akron, OH 44308 | | |
| | Telephone (800)736-3402 | | |
| | | | |
1-3583 | | THE TOLEDO EDISON COMPANY
| | 34-4375005 |
| | (An Ohio Corporation) | | |
| | c/o FirstEnergy Corp. | | |
| | 76 South Main Street | | |
| | Akron, OH 44308 | | |
| | Telephone (800)736-3402 | | |
| | | | | |
| 1-3141 | | JERSEY CENTRAL POWER & LIGHT COMPANY | | 21-0485010 |
| | | (A New Jersey Corporation) | | |
| | | c/o FirstEnergy Corp. | | |
| | | 76 South Main Street | | |
| | | Akron, OH 44308 | | |
| | | Telephone (800)736-3402 | | |
| | | | |
1-446 | | METROPOLITAN EDISON COMPANY
| | 23-0870160 |
| | (A Pennsylvania Corporation) | | |
| | c/o FirstEnergy Corp. | | |
| | 76 South Main Street | | |
| | Akron, OH 44308 | | |
| | Telephone (800)736-3402 | | |
| | | | |
1-3522 | | PENNSYLVANIA ELECTRIC COMPANY
| | 25-0718085 |
| | (A Pennsylvania Corporation) | | |
| | c/o FirstEnergy Corp. | | |
| | 76 South Main Street | | |
| | Akron, OH 44308 | | |
| | Telephone (800)736-3402 | | |
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.
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Yesþ Noo | | FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company The Cleveland Electric Illuminating Company, The Toledo Edison Company,and 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).
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Yesþ Noo | | FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company The Cleveland Electric Illuminating Company, The Toledo Edison Company,and 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 accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
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Large Accelerated Filerþ | | FirstEnergy Corp. |
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Accelerated Filero | | N/A |
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Non-accelerated Filer (Do not check
if a smaller reporting company)þ | | FirstEnergy Solutions Corp., Ohio Edison Company The Cleveland Electric Illuminating Company, The Toledo Edison Company,and Jersey Central Power & Light Company Metropolitan Edison Company and Pennsylvania Electric Company |
| | |
Smaller Reporting Companyo | | N/A |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
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Yeso Noþ | | FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company The Cleveland Electric Illuminating Company, The Toledo Edison Company,and Jersey Central Power & Light Company, Metropolitan Edison Company and Pennsylvania Electric Company |
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
|
| | | | |
| | | OUTSTANDING | |
| CLASS | | AS OF JULY 29, 2011 | AUGUST 6, 2012 |
| FirstEnergy Corp., $.10 par value | | | 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 | | | 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,and 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,and 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 web site at www.firstenergycorp.com.
These reports are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post important information on FirstEnergy’s Internet web site and recognize FirstEnergy’s Internet web site as 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 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,and 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’smanagement's intents, beliefs and current expectations. These statements typically contain, but are not limited to, the terms “anticipate,” “potential,” “expect,” “believe,” “estimate” and similar words. Forward-looking statements involve estimates, assumptions, known and unknown risks, uncertainties and other factors that may cause actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by such forward-looking statements.
Actual results may differ materially due to:
The speed and nature of increased competition in the electric utility industry.
The impact of the regulatory process on the pending matters before FERC and in the various states in which we do business including, but not limited to, matters related to rates.
The status of the PATH project in light of PJM’sPJM'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.
BusinessThe uncertainties of various cost recovery and regulatory impactscost allocation issues resulting from ATSI’sATSI's realignment into PJM Interconnection, L.L.C.PJM.
Economic or weather conditions affecting future sales and margins.
Changes in markets for energy services.
Changing energy and commodity market prices and availability.
Financial derivative reforms that could increase our liquidity needs and collateral costs.
The continued ability of FirstEnergy’sour regulated utilities to collect transition and other costs.
Operation and maintenance costs being higher than anticipated.
Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including CSAPR which was stayed by the Cross-State Air Pollution Rule (CSAPR),courts on December 30, 2011, and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric generating units.EPA's MATS rules.
The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including 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).
The uncertainties associated with our plan to deactivate our older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments, and the timing of those deactivations as they relate to, among other things, the RMR arrangements and the reliability of the transmission grid.
Issues that could result from the NRC's review of the indications of cracking in the Davis Besse Plant shield building.
Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC includingor as a result of the incident at Japan’sJapan's Fukushima Daiichi Nuclear Plant).
Adverse legal decisions and outcomes related to Met-Ed’sME's and Penelec’sPN's ability to recover certain transmission costs through their transmission service charge riders.
The continuing availability of generating units, and changes in their ability to operate at or near full capacity.operational status and any related impacts on vendor commitments.
Replacement power costs being higher than anticipated or inadequately hedged.
The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.
Changes in customers’customers' demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.
The ability to accomplish or realize anticipated benefits from strategic goals.
Efforts and ourOur ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coalfuel and coalfuel transportation on such margins.
The ability to experience growth in the distribution business.
The changingChanging market conditions that could affect the measurement of liabilities and the value of assets held in FirstEnergy’s nuclear decommissioning trusts,our NDTs, pension trusts and other trust funds, and cause us and our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.
The impact of changes to material accounting policies.
The ability to access the public securities and other capital and credit markets in accordance with FirstEnergy’sour financing plan,plans, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergyus and itsour subsidiaries.
Changes in general economic conditions affecting FirstEnergyus and itsour subsidiaries.
Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy’sus and its subsidiaries’our subsidiaries' access to financing, or theirincreased costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.
The continuing uncertaintystate of the national and regional economy and its impact on FirstEnergy’s and its subsidiaries’our major industrial and commercial customers.
Issues concerning the soundness of domestic and foreign financial institutions and counterparties with which FirstEnergy and its subsidiarieswe do business.
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’our SEC filings, and other similar factors.
Dividends declared from time to time on FirstEnergy’sFE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’sFE'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’FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.
TABLE OF CONTENTS
| TABLE OF CONTENTS |
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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:
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|
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| 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 |
AET | | Allegheny Energy Transmission, LLC, a parent of TrAIL and PATH |
| AGC | | Allegheny Generating Company, a generation subsidiary of AE |
| Allegheny | | Allegheny Energy, Inc., together with its consolidated subsidiaries |
AVEAllegheny Utilities | | Allegheny Ventures, Inc.MP, PE and WP |
| ATSI | | American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET in April 2012, which owns and operates transmission facilitiesfacilities. |
| CEI | | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary |
FENOCFE | FirstEnergy Corp., a public utility holding company |
| 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 |
FEVFET | FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, a subsidiary of AE, which is the parent of ATSI and TrAIL and has a joint venture in PATH. |
| FEV | FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures |
| FGCO | | FirstEnergy Generation Corp., a subsidiary of FES, which owns and operates non-nuclear generating facilities |
| FirstEnergy | | FirstEnergy Corp., together with its consolidated subsidiaries |
| Global Holding | Global Mining Holding Company, LLC, a public utility holding companyjoint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns Global Rail and Signal Peak |
| Global Rail | | A joint venture between FEV, WMB Marketing Ventures, LLC and WMB Loan Ventures II LLC,Gunvor Group, Ltd. that owns coal transportation operations near Roundup, Montana |
GPU | | GPU, Inc., former parent of JCP&L Met-Ed and Penelec, that merged with FirstEnergy on November 7, 2001 |
JCP&L | | Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary |
Met-Ed | ME | 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., a subsidiary of FES, which 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.AEP |
PATH-VA | PATH-Allegheny | PATH Allegheny Virginia Transmission CorporationCompany, LLC |
| PE | | The Potomac Edison Company, a Maryland electric utility operating subsidiary of AE |
Penelec | PN | 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,ME, PN, Penn and WP |
| PNBV | | PNBV Capital Trust, a special purpose entity created by OE in 1996 |
| Shippingport | | Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 |
| Signal Peak | | A joint venture between FEV, and WMB LoanMarketing Ventures, LLC and Gunvor Group, Ltd. that owns mining operations near Roundup, Montana |
| TE | | The Toledo Edison Company, an Ohio electric utility operating subsidiary |
| TrAIL | | Trans-Allegheny Interstate Line Company, a subsidiary of FET, which owns and operates transmission facilities |
| Utilities | | OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec,ME, PN, MP, PE and WP |
Utility Registrants | | OE, CEI, TE, JCP&L, Met-Ed and Penelec |
| WP | | West Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE |
| |
| The following abbreviations and acronyms are used to identify frequently used terms in this report: |
|
| ALJ | | Administrative Law Judge |
AOCLAnker WV | Anker West Virginia Mining Company, Inc. |
| Anker Coal | Anker Coal Group, Inc. |
| AOCI | Accumulated Other Comprehensive LossIncome |
| AEP | | American Electric Power Company, Inc. |
AQCAREPA | | Air Quality Control |
ARO | | Asset Retirement ObligationAlternative and Renewable Energy Portfolio Act |
| ARR | | Auction Revenue RightsRight |
| ASLB | Atomic Safety and Licensing Board |
GLOSSARY OF TERMS, Continued
|
| |
| BGS | | Basic Generation Service |
| BMP | | Bruce Mansfield Plant |
CAABTU | British Thermal Units |
| CAA | Clean Air Act |
CAIRCAL | Confirmatory Action Letter |
| CAIR | Clean Air Interstate Rule |
CAMR | | Clean Air Mercury Rule |
CATR | | Clean Air Transport Rule |
| CBP | | Competitive Bid Process |
iii
GLOSSARY OF TERMS, Cont’d.
| | |
|
| CCB | | Coal Combustion By-products |
| CDWR | | California Department of Water Resources |
| CERCLA | Comprehensive Environmental Response, Compensation, and Liability Act of 1980 |
CO2 | | Carbon Dioxide |
| CSAPR | | Cross-State Air Pollution Rule |
CTC | | Competitive Transition Charge |
| CWA | | Clean Water Act |
CWIP | | Construction Work in Progress |
| DCPD | | Deferred Compensation Plan for Outside Directors |
DOEDCR | Delivery Capital Recovery Rider |
| DOE | United States Department of Energy |
| DOJ | | United States Department of Justice |
DPA | | Department of the Public Advocate, Division of Rate Counsel (New Jersey) |
| DSP | | Default Service Plan |
EDCPEDC | Electric Distribution Company |
| EDCP | Executive Deferred Compensation Plan |
| EE&C | | Energy Efficiency and Conservation |
EISEGS | | Energy Insurance Services, Inc.Electric Generation Supplier |
EMPEHB | | Energy Master PlanEnvironmental Hearing Board |
| ENEC | | Expanded Net Energy Cost |
| EPA | | United States Environmental Protection Agency |
ESOPERO | | Employee Stock Ownership PlanElectric Reliability Organization |
| ESP | | Electric Security Plan |
FASB | | Financial Accounting Standards Board |
| FERC | | Federal Energy Regulatory Commission |
FMBFitch | Fitch Ratings |
| FMB | First Mortgage Bond |
| FPA | | Federal Power Act |
FRR | | Fixed Resource Requirement |
FTRs | FTR | Financial Transmission RightsRight |
| GAAP | | Accounting Principles Generally Accepted Accounting Principles in the United States |
RGGI | | Regional Greenhouse Gas Initiative of America |
| GHG | | Greenhouse Gases |
IRSGWH | Gigawatt-hour |
| HCL | Hydrochloric Acid |
| ICG | International Coal Group Inc. |
| ILP | Integrated License Application Process |
| IRS | Internal Revenue Service |
JOAIT | | Joint Operating AgreementInformation Technology |
| kV | | Kilovolt |
| KWH | | Kilowatt-hoursKilowatt-hour |
| LBR | | Little Blue Run |
LEDLCAPP | Long-Term Capacity Agreement Pilot Program |
| LITE | Light-Emitting DiodeLocal Infrastructure and Transmission Enhancement |
| LOC | | Letter of Credit |
| LSE | | Load Serving Entity |
| LTIP | | Long-Term Incentive Plan |
MACTMATS | | Maximum Achievable Control Technology |
MDE | | Maryland Department of the EnvironmentMercury and Air Toxics Standards |
| MDPSC | | Maryland Public Service Commission |
MEIUG | | Met-Ed Industrial Users Group |
| MISO | | Midwest Independent Transmission System Operator, Inc. |
GLOSSARY OF TERMS, Continued
|
| |
| Moody’s | | Moody’s Investors Service, Inc. |
MRO | | Market Rate Offer |
MSHA | | Mine Safety and Health Administration |
| MTEP | | MISO Regional Transmission Expansion Plan |
| MVP | | Multi-value Project |
| MW | | MegawattsMegawatt |
| MWH | | Megawatt-hoursMegawatt-hour |
NAAQSNCEA | | National Ambient Air Quality StandardsNERC Compliance Enforcement Authority |
| NDT | | Nuclear Decommissioning TrustsTrust |
| NEPA | National Environmental Policy Act |
| NERC | | North American Electric Reliability Corporation |
| NJBPU | | New Jersey Board of Public Utilities |
NNSRNMB | Non-Market Based |
| NNSR | Non-Attainment New Source Review |
NOAC | | Northwest Ohio Aggregation Coalition |
NOPEC | | Northeast Ohio Public Energy Council |
| NOV | | Notice of Violation |
NOX
| NOx | Nitrogen Oxide |
| NPDES | | National Pollutant Discharge Elimination System |
| NRC | | Nuclear Regulatory Commission |
iv
GLOSSARY OF TERMS, Cont’d.
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| NSR | | New Source Review |
| NUG | | Non-Utility Generation |
NUGCNYPSC | | Non-Utility Generation ChargeNew York State Public Service Commission |
| NYSEG | | New York State Electric and Gas |
OCC | | Ohio Consumers’ Counsel |
| OCI | | Other Comprehensive Income |
| OPEB | | Other Post-Employment Benefits |
OSBAOTTI | | Office of Small Business AdvocateOther Than Temporary Impairments |
| OVEC | | Ohio Valley Electric Corporation |
| PA DEP | | Pennsylvania Department of Environmental Protection |
| PCRB | | Pollution Control Revenue Bond |
PICA | | Pennsylvania Intergovernmental Cooperation Authority |
| PJM | | PJM Interconnection L. L. C.LLC |
| PM | Particulate Matter |
| POLR | | Provider of Last Resort; an electric utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver serviceResort |
| PPUC | | Pennsylvania Public Utility Commission |
PSCWV | | Public Service Commission of West Virginia |
| PSA | | Power Supply Agreement |
| PSD | | Prevention of Significant Deterioration |
| PUCO | | Public Utilities Commission of Ohio |
| PURPA | | Public Utility Regulatory Policies Act of 1978 |
RECs | REC | Renewable Energy CreditsCredit |
| RFC | ReliabilityFirst |
| RFP | | Request for Proposal |
| RGGI | | Regional Greenhouse Gas Initiative |
RPMRMR | Reliability Must-Run |
| RPM | Reliability Pricing Model |
| RTEP | | Regional Transmission Expansion Plan |
RTC | | Regulatory Transition Charge |
| RTO | | Regional Transmission Organization |
| S&P | | Standard & Poor’s Ratings Service |
| SB221 | | Amended Substitute Senate Bill 221 |
| SBC | | Societal Benefits Charge |
| SEC | | U.S.United States Securities and Exchange Commission |
| SIP | | State Implementation Plan(s) Under the Clean Air Act |
| SMIP | | Smart Meter Implementation Plan |
SNCR | | Selective Non-Catalytic Reduction |
SO2 | | Sulfur Dioxide |
| SOS | | Standard Offer Service |
TBCSREC | Solar Renewable Energy Credit |
GLOSSARY OF TERMS, Continued
|
| Transition Bond Charge |
| TDS | | Total Dissolved Solid |
| TMDL | | Total Maximum Daily Load |
| TMI-2 | | Three Mile Island Unit 2 |
| TSC | | Transmission Service Charge |
| VIE | | Variable Interest Entity |
| VSCC | | Virginia State Corporation Commission |
| WVDEP | | West Virginia Department of Environmental Protection |
| WVPSC | | Public Service Commission of West Virginia |
v
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | |
| | | Ended June 30 | | | Ended June 30 | |
| In millions, except per share amounts | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric utilities | | $ | 2,590 | | | $ | 2,373 | | | $ | 4,925 | | | $ | 4,916 | |
| Unregulated businesses | | | 1,470 | | | | 766 | | | | 2,711 | | | | 1,522 | |
| | | | | | | | | | | | | |
| Total revenues* | | | 4,060 | | | | 3,139 | | | | 7,636 | | | | 6,438 | |
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EXPENSES: | | | | | | | | | | | | | | | | |
| Fuel | | | 635 | | | | 350 | | | | 1,088 | | | | 684 | |
| Purchased power | | | 1,220 | | | | 1,063 | | | | 2,406 | | | | 2,301 | |
| Other operating expenses | | | 1,105 | | | | 673 | | | | 2,138 | | | | 1,374 | |
| Provision for depreciation | | | 282 | | | | 190 | | | | 502 | | | | 383 | |
| Amortization of regulatory assets | | | 90 | | | | 161 | | | | 222 | | | | 373 | |
| General taxes | | | 242 | | | | 176 | | | | 479 | | | | 381 | |
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| Total expenses | | | 3,574 | | | | 2,613 | | | | 6,835 | | | | 5,496 | |
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OPERATING INCOME | | | 486 | | | | 526 | | | | 801 | | | | 942 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | | 31 | | | | 31 | | | | 52 | | | | 47 | |
| Interest expense | | | (265 | ) | | | (207 | ) | | | (496 | ) | | | (420 | ) |
| Capitalized interest | | | 20 | | | | 40 | | | | 38 | | | | 81 | |
| | | | | | | | | | | | | |
| Total other expense | | | (214 | ) | | | (136 | ) | | | (406 | ) | | | (292 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 272 | | | | 390 | | | | 395 | | | | 650 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 101 | | | | 134 | | | | 179 | | | | 245 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | | 171 | | | | 256 | | | | 216 | | | | 405 | |
| | | | | | | | | | | | | | | | | |
| Loss attributable to noncontrolling interest | | | (10 | ) | | | (9 | ) | | | (15 | ) | | | (15 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EARNINGS AVAILABLE TO FIRSTENERGY CORP. | | $ | 181 | | | $ | 265 | | | $ | 231 | | | $ | 420 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.43 | | | $ | 0.87 | | | $ | 0.61 | | | $ | 1.38 | |
| Diluted | | $ | 0.43 | | | $ | 0.87 | | | $ | 0.61 | | | $ | 1.37 | |
AVERAGE SHARES OUTSTANDING: | | | | | | | | | | | | | | | | |
| Basic | | | 418 | | | | 304 | | | | 380 | | | | 304 | |
| Diluted | | | 420 | | | | 305 | | | | 382 | | | | 305 | |
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | | — | | | | — | | | $ | 0.55 | | | $ | 0.55 | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months Ended June 30 |
| (In millions, except per share amounts) | | 2012 | | 2011 | | 2012 | | 2011 |
| | | | | | | | | |
| REVENUES: | | | | | | | | |
| Electric utilities | | $ | 2,279 |
| | $ | 2,590 |
| | $ | 4,790 |
| | $ | 4,925 |
|
| Unregulated businesses | | 1,590 |
| | 1,470 |
| | 3,157 |
| | 2,711 |
|
| Total revenues* | | 3,869 |
| | 4,060 |
| | 7,947 |
| | 7,636 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | |
| Fuel | | 656 |
| | 635 |
| | 1,197 |
| | 1,088 |
|
| Purchased power | | 1,156 |
| | 1,220 |
| | 2,503 |
| | 2,406 |
|
| Other operating expenses | | 914 |
| | 1,065 |
| | 1,726 |
| | 2,058 |
|
| Provision for depreciation | | 292 |
| | 287 |
| | 577 |
| | 512 |
|
| Amortization of regulatory assets, net | | 62 |
| | 90 |
| | 137 |
| | 222 |
|
| General taxes | | 232 |
| | 242 |
| | 504 |
| | 479 |
|
| Total operating expenses | | 3,312 |
| | 3,539 |
| | 6,644 |
| | 6,765 |
|
| | | | | | | | | |
| OPERATING INCOME | | 557 |
| | 521 |
| | 1,303 |
| | 871 |
|
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | 13 |
| | 31 |
| | 24 |
| | 52 |
|
| Interest expense | | (274 | ) | | (265 | ) | | (520 | ) | | (496 | ) |
| Capitalized interest | | 19 |
| | 20 |
| | 36 |
| | 38 |
|
| Total other expense | | (242 | ) | | (214 | ) | | (460 | ) | | (406 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 315 |
| | 307 |
| | 843 |
| | 465 |
|
| | | | | | | | | |
| INCOME TAXES | | 127 |
| | 114 |
| | 349 |
| | 225 |
|
| | | | | | | | | |
| NET INCOME | | 188 |
| | 193 |
| | 494 |
| | 240 |
|
| | | | | | | | | |
| Income (loss) attributable to noncontrolling interest | | 1 |
| | (10 | ) | | 1 |
| | (15 | ) |
| | | | | | | | | |
| EARNINGS AVAILABLE TO FIRSTENERGY CORP. | | $ | 187 |
| | $ | 203 |
| | $ | 493 |
| | $ | 255 |
|
| | | | | | | | | |
| EARNINGS PER SHARE OF COMMON STOCK: | | | | | | | | |
| Basic | | $ | 0.45 |
| | $ | 0.48 |
| | $ | 1.18 |
| | $ | 0.67 |
|
| Diluted | | $ | 0.45 |
| | $ | 0.48 |
| | $ | 1.18 |
| | $ | 0.67 |
|
| | | | | | | | | |
| WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING: | | | | | | | | |
| Basic | | 417 |
| | 418 |
| | 418 |
| | 380 |
|
| Diluted | | 419 |
| | 420 |
| | 419 |
| | 382 |
|
| | | | | | | | | |
| DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | — |
| | $ | — |
| | $ | 0.55 |
| | $ | 0.55 |
|
| | |
| * | | Includes excise tax collections of $116$107 million and $99$116 million in the three months ended June 30, 20112012 and 2010,2011, respectively, and $235$228 million and $208$235 million in the six months ended June 30, 20112012 and 2010,2011, respectively. |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
1
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | |
| | | Three Months | | | Six Months | |
| | | Ended June 30 | | | Ended June 30 | |
| (In millions) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 171 | | | $ | 256 | | | $ | 216 | | | $ | 405 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 111 | | | | 17 | | | | 130 | | | | 30 | |
| Unrealized gain on derivative hedges | | | 17 | | | | 6 | | | | 11 | | | | 10 | |
| Change in unrealized gain on available-for-sale securities | | | 10 | | | | 6 | | | | 19 | | | | 12 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 138 | | | | 29 | | | | 160 | | | | 52 | |
| Income tax expense related to other comprehensive income | | | 53 | | | | 9 | | | | 54 | | | | 16 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 85 | | | | 20 | | | | 106 | | | | 36 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | 256 | | | | 276 | | | | 322 | | | | 441 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE LOSS ATTRIBUTABLE | | | | | | | | | | | | | | | | |
TO NONCONTROLLING INTEREST | | | (10 | ) | | | (9 | ) | | | (15 | ) | | | (15 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. | | $ | 266 | | | $ | 285 | | | $ | 337 | | | $ | 456 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 | | 2012 | | 2011 |
| | | | | | | | | |
| NET INCOME | | $ | 188 |
| | $ | 193 |
| | $ | 494 |
| | $ | 240 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pensions and OPEB prior service costs | | (48 | ) | | 48 |
| | (101 | ) | | 4 |
|
| Amortized losses on derivative hedges | | 3 |
| | 17 |
| | 1 |
| | 11 |
|
| Change in unrealized gain on available-for-sale securities | | 2 |
| | 10 |
| | 12 |
| | 19 |
|
| Other comprehensive income (loss) | | (43 | ) | | 75 |
| | (88 | ) | | 34 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | (27 | ) | | 33 |
| | (51 | ) | | 14 |
|
| Other comprehensive income (loss), net of tax | | (16 | ) | | 42 |
| | (37 | ) | | 20 |
|
| | | | | | | | | |
| COMPREHENSIVE INCOME | | 172 |
| | 235 |
| | 457 |
| | 260 |
|
| | | | | | | | | |
| Comprehensive income (loss) attributable to noncontrolling interest | | 1 |
| | (10 | ) | | 1 |
| | (15 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP. | | $ | 171 |
| | $ | 245 |
| | $ | 456 |
| | $ | 275 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
2
FIRSTENERGY CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In millions) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 476 | | | $ | 1,019 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $35 in 2011 and $36 in 2010 | | | 1,578 | | | | 1,392 | |
| Other, net of allowance for uncollectible accounts of $8 in 2011 and 2010 | | | 256 | | | | 176 | |
| Materials and supplies, at average cost | | | 866 | | | | 638 | |
| Prepaid taxes | | | 474 | | | | 199 | |
| Derivatives | | | 265 | | | | 182 | |
| Other | | | 203 | | | | 92 | |
| | | | | | | |
| | | | 4,118 | | | | 3,698 | |
| | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 39,568 | | | | 29,451 | |
| Less — Accumulated provision for depreciation | | | 11,593 | | | | 11,180 | |
| | | | | | | |
| | | | 27,975 | | | | 18,271 | |
| Construction work in progress | | | 1,465 | | | | 1,517 | |
| Property, plant and equipment held for sale, net | | | 502 | | | | — | |
| | | | | | | |
| | | | 29,942 | | | | 19,788 | |
| | | | | | | |
INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 2,051 | | | | 1,973 | |
| Investments in lease obligation bonds | | | 414 | | | | 476 | |
| Nuclear fuel disposal trust | | | 212 | | | | 208 | |
| Other | | | 479 | | | | 345 | |
| | | | | | | |
| | | | 3,156 | | | | 3,002 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 6,456 | | | | 5,575 | |
| Regulatory assets | | | 2,182 | | | | 1,826 | |
| Intangible assets | | | 973 | | | | 256 | |
| Other | | | 769 | | | | 660 | |
| | | | | | | |
| | | | 10,380 | | | | 8,317 | |
| | | | | | | |
| | | $ | 47,596 | | | $ | 34,805 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 2,058 | | | $ | 1,486 | |
| Short-term borrowings | | | 656 | | | | 700 | |
| Accounts payable | | | 1,122 | | | | 872 | |
| Accrued taxes | | | 399 | | | | 326 | |
| Accrued compensation and benefits | | | 331 | | | | 315 | |
| Derivatives | | | 287 | | | | 266 | |
| Other | | | 691 | | | | 733 | |
| | | | | | | |
| | | | 5,544 | | | | 4,698 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholders’ equity- | | | | | | | | |
| Common stock, $0.10 par value, authorized 490,000,000 and 375,000,000 shares, respectively- 418,216,437 and 304,835,407 shares outstanding, respectively | | | 42 | | | | 31 | |
| Other paid-in capital | | | 9,782 | | | | 5,444 | |
| Accumulated other comprehensive loss | | | (1,433 | ) | | | (1,539 | ) |
| Retained earnings | | | 4,607 | | | | 4,609 | |
| | | | | | | |
| Total common stockholders’ equity | | | 12,998 | | | | 8,545 | |
| Noncontrolling interest | | | (48 | ) | | | (32 | ) |
| | | | | | | |
| Total equity | | | 12,950 | | | | 8,513 | |
| Long-term debt and other long-term obligations | | | 16,491 | | | | 12,579 | |
| | | | | | | |
| | | | 29,441 | | | | 21,092 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 5,219 | | | | 2,879 | |
| Retirement benefits | | | 2,134 | | | | 1,868 | |
| Asset retirement obligations | | | 1,459 | | | | 1,407 | |
| Deferred gain on sale and leaseback transaction | | | 942 | | | | 959 | |
| Adverse power contract liability | | | 649 | | | | 466 | |
| Other | | | 2,208 | | | | 1,436 | |
| | | | | | | |
| | | | 12,611 | | | | 9,015 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 47,596 | | | $ | 34,805 | |
| | | | | | | |
|
| | | | | | | | |
| (In millions, except share amounts) | | June 30,
2012 | | December 31,
2011 |
| ASSETS | | | | |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents | | $ | 94 |
| | $ | 202 |
|
| Receivables- | | | | |
| Customers, net of allowance for uncollectible accounts of $36 in 2012 and $37 in 2011 | | 1,635 |
| | 1,525 |
|
| Other, net of allowance for uncollectible accounts of $2 in 2012 and $3 in 2011 | | 263 |
| | 269 |
|
| Materials and supplies | | 921 |
| | 811 |
|
| Prepaid taxes | | 248 |
| | 191 |
|
| Derivatives | | 276 |
| | 235 |
|
| Other | | 171 |
| | 122 |
|
| | | 3,608 |
| | 3,355 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | | | |
| In service | | 41,167 |
| | 40,122 |
|
| Less — Accumulated provision for depreciation | | 12,336 |
| | 11,839 |
|
| | | 28,831 |
| | 28,283 |
|
| Construction work in progress | | 1,937 |
| | 2,054 |
|
| | | 30,768 |
| | 30,337 |
|
| INVESTMENTS: | | | | |
| Nuclear plant decommissioning trusts | | 2,153 |
| | 2,112 |
|
| Investments in lease obligation bonds | | 326 |
| | 402 |
|
| Other | | 1,039 |
| | 1,008 |
|
| | | 3,518 |
| | 3,522 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | |
| Goodwill | | 6,444 |
| | 6,441 |
|
| Regulatory assets | | 2,122 |
| | 2,030 |
|
| Other | | 1,588 |
| | 1,641 |
|
| | | 10,154 |
| | 10,112 |
|
| | | $ | 48,048 |
| | $ | 47,326 |
|
LIABILITIES AND CAPITALIZATION
| | | | |
| CURRENT LIABILITIES: | | | | |
| Currently payable long-term debt | | $ | 1,577 |
| | $ | 1,621 |
|
| Short-term borrowings | | 1,890 |
| | — |
|
| Accounts payable | | 1,052 |
| | 1,174 |
|
| Accrued taxes | | 436 |
| | 558 |
|
| Accrued compensation and benefits | | 288 |
| | 384 |
|
| Derivatives | | 222 |
| | 218 |
|
| Other | | 617 |
| | 900 |
|
| | | 6,082 |
| | 4,855 |
|
| CAPITALIZATION: | | | | |
| Common stockholders’ equity- | | | | |
| Common stock, $0.10 par value, authorized 490,000,000 shares - 418,216,437 shares outstanding | | 42 |
| | 42 |
|
| Other paid-in capital | | 9,756 |
| | 9,765 |
|
| Accumulated other comprehensive income | | 389 |
| | 426 |
|
| Retained earnings | | 3,310 |
| | 3,047 |
|
| Total common stockholders’ equity | | 13,497 |
| | 13,280 |
|
| Noncontrolling interest | | 15 |
| | 19 |
|
| Total equity | | 13,512 |
| | 13,299 |
|
| Long-term debt and other long-term obligations | | 15,159 |
| | 15,716 |
|
| | | 28,671 |
| | 29,015 |
|
| NONCURRENT LIABILITIES: | | | | |
| Accumulated deferred income taxes | | 6,042 |
| | 5,670 |
|
| Retirement benefits | | 2,257 |
| | 2,823 |
|
| Asset retirement obligations | | 1,548 |
| | 1,497 |
|
| Deferred gain on sale and leaseback transaction | | 909 |
| | 925 |
|
| Adverse power contract liability | | 559 |
| | 469 |
|
| Other | | 1,980 |
| | 2,072 |
|
| | | 13,295 |
| | 13,456 |
|
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | |
| |
|
| | | $ | 48,048 |
| | $ | 47,326 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
3
FIRSTENERGY CORP.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In millions) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 216 | | | $ | 405 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 502 | | | | 383 | |
| Amortization of regulatory assets | | | 222 | | | | 373 | |
| Nuclear fuel and lease amortization | | | 92 | | | | 76 | |
| Deferred purchased power and other costs | | | (168 | ) | | | (146 | ) |
| Deferred income taxes and investment tax credits, net | | | 552 | | | | 159 | |
| Deferred rents and lease market valuation liability | | | (61 | ) | | | (62 | ) |
| Accrued compensation and retirement benefits | | | 49 | | | | (27 | ) |
| Commodity derivative transactions, net | | | (21 | ) | | | (29 | ) |
| Pension trust contribution | | | (262 | ) | | | — | |
| Asset impairments | | | 41 | | | | 21 | |
| Cash collateral paid, net | | | (31 | ) | | | (63 | ) |
| Interest rate swap transactions | | | — | | | | 43 | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 199 | | | | (156 | ) |
| Materials and supplies | | | 24 | | | | (17 | ) |
| Prepayments and other current assets | | | (268 | ) | | | (81 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | (28 | ) | | | 18 | |
| Accrued taxes | | | (66 | ) | | | (58 | ) |
| Accrued interest | | | (4 | ) | | | 10 | |
| Other | | | 43 | | | | 9 | |
| | | | | | | |
| Net cash provided from operating activities | | | 1,031 | | | | 858 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | 503 | | | | — | |
| Short-term borrowings, net | | | — | | | | 281 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (1,002 | ) | | | (407 | ) |
| Short-term borrowings, net | | | (44 | ) | | | — | |
| Common stock dividend payments | | | (420 | ) | | | (335 | ) |
| Other | | | (76 | ) | | | (23 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (1,039 | ) | | | (484 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (1,018 | ) | | | (997 | ) |
| Proceeds from asset sales | | | — | | | | 116 | |
| Sales of investment securities held in trusts | | | 1,703 | | | | 1,915 | |
| Purchases of investment securities held in trusts | | | (1,807 | ) | | | (1,934 | ) |
| Customer acquisition costs | | | (2 | ) | | | (105 | ) |
| Cash investments | | | 50 | | | | 59 | |
| Cash received in Allegheny merger | | | 590 | | | | — | |
| Other | | | (51 | ) | | | (21 | ) |
| | | | | | | |
| Net cash used for investing activities | | | (535 | ) | | | (967 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (543 | ) | | | (593 | ) |
| Cash and cash equivalents at beginning of period | | | 1,019 | | | | 874 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 476 | | | $ | 281 | |
| | | | | | | |
| | | | | | | | | |
SUPPLEMENTAL CASH FLOW INFORMATION: | | | | | | | | |
| Non-cash transaction: merger with Allegheny, common stock issued | | $ | 4,354 | | | $ | — | |
|
| | | | | | | | |
| | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
| Net Income | | $ | 494 |
| | $ | 240 |
|
| Adjustments to reconcile net income to net cash from operating activities- | | | | |
| Provision for depreciation | | 577 |
| | 512 |
|
| Amortization of regulatory assets, net | | 137 |
| | 222 |
|
| Nuclear fuel and lease amortization | | 106 |
| | 92 |
|
| Deferred purchased power and other costs | | (149 | ) | | (168 | ) |
| Deferred income taxes and investment tax credits, net | | 423 |
| | 598 |
|
| Deferred rents and lease market valuation liability | | (106 | ) | | (61 | ) |
| Stock based compensation | | (18 | ) | | (4 | ) |
| Accrued compensation and retirement benefits | | (160 | ) | | (31 | ) |
| Commodity derivative transactions, net | | (86 | ) | | (21 | ) |
| Pension trust contributions | | (600 | ) | | (262 | ) |
| Asset impairments | | 7 |
| | 41 |
|
| Cash collateral, net | | 22 |
| | (31 | ) |
| Decrease (increase) in operating assets- | | | | |
| Receivables | | (105 | ) | | 199 |
|
| Materials and supplies | | (109 | ) | | 24 |
|
| Prepayments and other current assets | | (117 | ) | | (268 | ) |
| Decrease in operating liabilities- | | | | |
| Accounts payable | | (122 | ) | | (28 | ) |
| Accrued taxes | | (192 | ) | | (66 | ) |
| Accrued interest | | (5 | ) | | (4 | ) |
| Other | | 65 |
| | 47 |
|
| Net cash provided from operating activities | | 62 |
| | 1,031 |
|
| | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | |
| New Financing- | | | | |
| Long-term debt | | 182 |
| | 503 |
|
| Short-term borrowings, net | | 1,890 |
| | — |
|
| Redemptions and Repayments- | | | | |
| Long-term debt | | (746 | ) | | (1,002 | ) |
| Short-term borrowings, net | | — |
| | (44 | ) |
| Common stock dividend payments | | (460 | ) | | (420 | ) |
| Other | | (35 | ) | | (76 | ) |
| Net cash provided from (used for) financing activities | | 831 |
| | (1,039 | ) |
| | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | |
| Property additions | | (1,001 | ) | | (1,018 | ) |
| Sales of investment securities held in trusts | | 382 |
| | 1,703 |
|
| Purchases of investment securities held in trusts | | (420 | ) | | (1,807 | ) |
| Cash investments | | 87 |
| | 50 |
|
| Cash received in Allegheny merger | | — |
| | 590 |
|
| Other | | (49 | ) | | (53 | ) |
| Net cash used for investing activities | | (1,001 | ) | | (535 | ) |
| | | | | |
| Net change in cash and cash equivalents | | (108 | ) | | (543 | ) |
| Cash and cash equivalents at beginning of period | | 202 |
| | 1,019 |
|
| Cash and cash equivalents at end of period | | $ | 94 |
| | $ | 476 |
|
| | | | | |
| 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 | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In millions) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales to non-affiliates | | $ | 1,052 | | | $ | 729 | | | $ | 2,097 | | | $ | 1,397 | |
| Electric sales to affiliates | | | 170 | | | | 539 | | | | 431 | | | | 1,146 | |
| Other | | | 70 | | | | 58 | | | | 156 | | | | 171 | |
| | | | | | | | | | | | | |
| Total revenues | | | 1,292 | | | | 1,326 | | | | 2,684 | | | | 2,714 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Fuel | | | 316 | | | | 343 | | | | 659 | | | | 671 | |
| Purchased power from affiliates | | | 65 | | | | 69 | | | | 134 | | | | 130 | |
| Purchased power from non-affiliates | | | 329 | | | | 310 | | | | 626 | | | | 760 | |
| Other operating expenses | | | 429 | | | | 304 | | | | 910 | | | | 608 | |
| Provision for depreciation | | | 68 | | | | 63 | | | | 136 | | | | 126 | |
| General taxes | | | 30 | | | | 22 | | | | 60 | | | | 49 | |
| Impairment of long-lived assets | | | 7 | | | | — | | | | 20 | | | | 2 | |
| | | | | | | | | | | | | |
| Total expenses | | | 1,244 | | | | 1,111 | | | | 2,545 | | | | 2,346 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 48 | | | | 215 | | | | 139 | | | | 368 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | | 16 | | | | 13 | | | | 22 | | | | 14 | |
| Miscellaneous income (expense) | | | 4 | | | | 4 | | | | 8 | | | | 7 | |
| Interest expense — affiliates | | | (2 | ) | | | (2 | ) | | | (3 | ) | | | (5 | ) |
| Interest expense — other | | | (52 | ) | | | (51 | ) | | | (105 | ) | | | (101 | ) |
| Capitalized interest | | | 10 | | | | 24 | | | | 20 | | | | 44 | |
| | | | | | | | | | | | | |
| Total other expense | | | (24 | ) | | | (12 | ) | | | (58 | ) | | | (41 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 24 | | | | 203 | | | | 81 | | | | 327 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 4 | | | | 69 | | | | 25 | | | | 113 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 20 | | | $ | 134 | | | $ | 56 | | | $ | 214 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 20 | | | $ | 134 | | | $ | 56 | | | $ | 214 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 1 | | | | 1 | | | | 3 | | | | (9 | ) |
| Unrealized gain on derivative hedges | | | 14 | | | | 3 | | | | 5 | | | | 4 | |
| Change in unrealized gain on available-for-sale securities | | | 8 | | | | 6 | | | | 15 | | | | 11 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 23 | | | | 10 | | | | 23 | | | | 6 | |
| Income taxes related to other comprehensive income | | | 10 | | | | 4 | | | | 8 | | | | 2 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 13 | | | | 6 | | | | 15 | | | | 4 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 33 | | | $ | 140 | | | $ | 71 | | | $ | 218 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 | | 2012 | | 2011 |
| | | | | | | | | |
| STATEMENTS OF INCOME | | | | | | | | |
| REVENUES: | | | | | | | | |
| Electric sales to non-affiliates | | $ | 1,293 |
| | $ | 1,052 |
| | $ | 2,625 |
| | $ | 2,097 |
|
| Electric sales to affiliates | | 109 |
| | 170 |
| | 230 |
| | 431 |
|
| Other | | 54 |
| | 70 |
| | 117 |
| | 156 |
|
| Total revenues | | 1,456 |
| | 1,292 |
| | 2,972 |
| | 2,684 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | |
| Fuel | | 380 |
| | 316 |
| | 675 |
| | 659 |
|
| Purchased power from affiliates | | 133 |
| | 65 |
| | 250 |
| | 134 |
|
| Purchased power from non-affiliates | | 434 |
| | 329 |
| | 921 |
| | 626 |
|
| Other operating expenses | | 393 |
| | 413 |
| | 688 |
| | 878 |
|
| Provision for depreciation | | 69 |
| | 69 |
| | 132 |
| | 138 |
|
| General taxes | | 32 |
| | 30 |
| | 69 |
| | 60 |
|
| Impairment of long-lived assets | | — |
| | 7 |
| | — |
| | 20 |
|
| Total operating expenses | | 1,441 |
| | 1,229 |
| | 2,735 |
| | 2,515 |
|
| | | | | | | | | |
| OPERATING INCOME | | 15 |
| | 63 |
| | 237 |
| | 169 |
|
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | 6 |
| | 16 |
| | 12 |
| | 22 |
|
| Miscellaneous income | | 20 |
| | 4 |
| | 24 |
| | 8 |
|
| Interest expense — affiliates | | (2 | ) | | (2 | ) | | (4 | ) | | (3 | ) |
| Interest expense — other | | (48 | ) | | (52 | ) | | (89 | ) | | (105 | ) |
| Capitalized interest | | 9 |
| | 10 |
| | 18 |
| | 20 |
|
| Total other expense | | (15 | ) | | (24 | ) | | (39 | ) | | (58 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | — |
| | 39 |
| | 198 |
| | 111 |
|
| | | | | | | | | |
| INCOME TAXES | | 1 |
| | 10 |
| | 77 |
| | 37 |
|
| | | | | | | | | |
| NET INCOME (LOSS) | | $ | (1 | ) | | $ | 29 |
| | $ | 121 |
| | $ | 74 |
|
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| NET INCOME (LOSS) | | $ | (1 | ) | | $ | 29 |
| | $ | 121 |
| | $ | 74 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | |
| Pensions and OPEB prior service costs | | 8 |
| | (5 | ) | | 3 |
| | (9 | ) |
| Amortized gain (loss) on derivative hedges | | 1 |
| | 14 |
| | (4 | ) | | 5 |
|
| Change in unrealized gain on available-for-sale securities | | 3 |
| | 8 |
| | 13 |
| | 15 |
|
| Other comprehensive income | | 12 |
| | 17 |
| | 12 |
| | 11 |
|
| Income taxes on other comprehensive income | | 2 |
| | 8 |
| | 4 |
| | 4 |
|
| Other comprehensive income, net of tax | | 10 |
| | 9 |
| | 8 |
| | 7 |
|
| | | | | | | | | |
| COMPREHENSIVE INCOME | | $ | 9 |
| | $ | 38 |
| | $ | 129 |
| | $ | 81 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
5
FIRSTENERGY SOLUTIONS CORP.
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In millions) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 6 | | | $ | 9 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $18 in 2011 and $17 in 2010 | | | 450 | | | | 366 | |
| Associated companies | | | 490 | | | | 478 | |
| Other, net of allowances for uncollectible accounts of $3 in 2011 and $7 in 2010 | | | 51 | | | | 90 | |
| Notes receivable from associated companies | | | 490 | | | | 397 | |
| Materials and supplies, at average cost | | | 499 | | | | 545 | |
| Derivatives | | | 221 | | | | 182 | |
| Prepayments and other | | | 49 | | | | 59 | |
| | | | | | | |
| | | | 2,256 | | | | 2,126 | |
| | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | |
| In service | | | 11,455 | | | | 11,321 | |
| Less — Accumulated provision for depreciation | | | 4,206 | | | | 4,024 | |
| | | | | | | |
| | | | 7,249 | | | | 7,297 | |
| Construction work in progress | | | 694 | | | | 1,063 | |
| Property, plant and equipment held for sale, net | | | 487 | | | | — | |
| | | | | | | |
| | | | 8,430 | | | | 8,360 | |
| | | | | | | |
INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 1,184 | | | | 1,146 | |
| Other | | | 10 | | | | 12 | |
| | | | | | | |
| | | | 1,194 | | | | 1,158 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Customer intangibles | | | 129 | | | | 134 | |
| Goodwill | | | 24 | | | | 24 | |
| Property taxes | | | 41 | | | | 41 | |
| Unamortized sale and leaseback costs | | | 76 | | | | 73 | |
| Derivatives | | | 135 | | | | 98 | |
| Other | | | 75 | | | | 48 | |
| | | | | | | |
| | | | 480 | | | | 418 | |
| | | | | | | |
| | | $ | 12,360 | | | $ | 12,062 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,088 | | | $ | 1,132 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 541 | | | | 12 | |
| Other | | | 1 | | | | — | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 393 | | | | 467 | |
| Other | | | 191 | | | | 241 | |
| Derivatives | | | 242 | | | | 266 | |
| Other | | | 262 | | | | 322 | |
| | | | | | | |
| | | | 2,718 | | | | 2,440 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholder’s equity- | | | | | | | | |
| Common stock, without par value, authorized 750 shares- 7 shares outstanding | | | 1,488 | | | | 1,490 | |
| Accumulated other comprehensive loss | | | (105 | ) | | | (120 | ) |
| Retained earnings | | | 2,474 | | | | 2,418 | |
| | | | | | | |
| Total common stockholder’s equity | | | 3,857 | | | | 3,788 | |
| Long-term debt and other long-term obligations | | | 3,000 | | | | 3,181 | |
| | | | | | | |
| | | | 6,857 | | | | 6,969 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | 942 | | | | 959 | |
| Accumulated deferred income taxes | | | 216 | | | | 58 | |
| Asset retirement obligations | | | 875 | | | | 892 | |
| Retirement benefits | | | 295 | | | | 285 | |
| Lease market valuation liability | | | 194 | | | | 217 | |
| Derivatives | | | 85 | | | | 81 | |
| Other | | | 178 | | | | 161 | |
| | | | | | | |
| | | | 2,785 | | | | 2,653 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 12,360 | | | $ | 12,062 | |
| | | | | | | |
|
| | | | | | | | |
| (In millions, except share amounts) | | June 30,
2012 | | December 31,
2011 |
| ASSETS | | | | |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents | | $ | 7 |
| | $ | 7 |
|
| Receivables- | | | | |
| Customers, net of allowance for uncollectible accounts of $16 in 2012 and 2011 | | 457 |
| | 424 |
|
| Affiliated companies | | 537 |
| | 600 |
|
| Other, net of allowance for uncollectible accounts of $2 in 2012 and $3 in 2011 | | 96 |
| | 61 |
|
| Notes receivable from affiliated companies | | 228 |
| | 383 |
|
| Materials and supplies | | 548 |
| | 492 |
|
| Derivatives | | 265 |
| | 219 |
|
| Prepayments and other | | 19 |
| | 38 |
|
| | | 2,157 |
| | 2,224 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | | | |
| In service | | 11,375 |
| | 10,983 |
|
| Less — Accumulated provision for depreciation | | 4,314 |
| | 4,110 |
|
| | | 7,061 |
| | 6,873 |
|
| Construction work in progress | | 919 |
| | 1,014 |
|
| | | 7,980 |
| | 7,887 |
|
| INVESTMENTS: | | | | |
| Nuclear plant decommissioning trusts | | 1,250 |
| | 1,223 |
|
| Other | | 7 |
| | 7 |
|
| | | 1,257 |
| | 1,230 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | |
| Customer intangibles | | 118 |
| | 123 |
|
| Goodwill | | 24 |
| | 24 |
|
| Property taxes | | 43 |
| | 43 |
|
| Unamortized sale and leaseback costs | | 118 |
| | 80 |
|
| Derivatives | | 110 |
| | 79 |
|
| Other | | 137 |
| | 129 |
|
| | | 550 |
| | 478 |
|
| | | $ | 11,944 |
| | $ | 11,819 |
|
| LIABILITIES AND CAPITALIZATION | | | | |
| CURRENT LIABILITIES: | | | | |
| Currently payable long-term debt | | $ | 1,144 |
| | $ | 905 |
|
| Accounts payable- | | | | |
| Affiliated companies | | 608 |
| | 436 |
|
| Other | | 306 |
| | 220 |
|
| Accrued taxes | | 62 |
| | 227 |
|
| Derivatives | | 219 |
| | 189 |
|
| Other | | 242 |
| | 261 |
|
| | | 2,581 |
| | 2,238 |
|
| CAPITALIZATION: | | | | |
| Common stockholder's equity- | | | | |
| Common stock, without par value, authorized 750 shares- 7 shares outstanding | | 1,568 |
| | 1,570 |
|
| Accumulated other comprehensive income | | 84 |
| | 76 |
|
| Retained earnings | | 2,052 |
| | 1,931 |
|
| Total common stockholder's equity | | 3,704 |
| | 3,577 |
|
| Long-term debt and other long-term obligations | | 2,500 |
| | 2,799 |
|
| | | 6,204 |
| | 6,376 |
|
| NONCURRENT LIABILITIES: | | | | |
| Deferred gain on sale and leaseback transaction | | 909 |
| | 925 |
|
| Accumulated deferred income taxes | | 436 |
| | 286 |
|
| Asset retirement obligations | | 934 |
| | 904 |
|
| Retirement benefits | | 179 |
| | 356 |
|
| Lease market valuation liability | | 148 |
| | 171 |
|
| Other | | 553 |
| | 563 |
|
| | | 3,159 |
| | 3,205 |
|
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | |
| |
|
| | | $ | 11,944 |
| | $ | 11,819 |
|
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)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In millions) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 56 | | | $ | 214 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 136 | | | | 126 | |
| Nuclear fuel and lease amortization | | | 92 | | | | 78 | |
| Deferred rents and lease market valuation liability | | | (58 | ) | | | (59 | ) |
| Deferred income taxes and investment tax credits, net | | | 126 | | | | 114 | |
| Asset impairments | | | 28 | | | | 21 | |
| Accrued compensation and retirement benefits | | | 8 | | | | 7 | |
| Commodity derivative transactions, net | | | (60 | ) | | | (29 | ) |
| Cash collateral paid, net | | | (40 | ) | | | (38 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | (36 | ) | | | (193 | ) |
| Materials and supplies | | | 50 | | | | (29 | ) |
| Prepayments and other current assets | | | 12 | | | | 25 | |
| Decrease in operating liabilities- | | | | | | | | |
| Accounts payable | | | (124 | ) | | | (32 | ) |
| Accrued taxes | | | (29 | ) | | | (8 | ) |
| Other | | | 21 | | | | 21 | |
| | | | | | | |
| Net cash provided from operating activities | | | 182 | | | | 218 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New financing- | | | | | | | | |
| Long-term debt | | | 247 | | | | — | |
| Short-term borrowings, net | | | 530 | | | | 76 | |
| Redemptions and repayments- | | | | | | | | |
| Long-term debt | | | (472 | ) | | | (295 | ) |
| Other | | | (11 | ) | | | (1 | ) |
| | | | | | | |
| Net cash provided from (used for) financing activities | | | 294 | | | | (220 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (334 | ) | | | (566 | ) |
| Proceeds from asset sales | | | — | | | | 116 | |
| Sales of investment securities held in trusts | | | 513 | | | | 957 | |
| Purchases of investment securities held in trusts | | | (545 | ) | | | (979 | ) |
| Loans to associated companies, net | | | (93 | ) | | | 631 | |
| Customer acquisition costs | | | (2 | ) | | | (105 | ) |
| Leasehold improvement payments to associated companies | | | — | | | | (51 | ) |
| Other | | | (18 | ) | | | (1 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (479 | ) | | | 2 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (3 | ) | | | — | |
| Cash and cash equivalents at beginning of period | | | 9 | | | | — | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 6 | | | $ | — | |
| | | | | | | |
|
| | | | | | | | |
| | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 |
| | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
| Net Income | | $ | 121 |
| | $ | 74 |
|
| Adjustments to reconcile net income to net cash from operating activities- | | | | |
| Provision for depreciation | | 132 |
| | 138 |
|
| Nuclear fuel and lease amortization | | 103 |
| | 92 |
|
| Deferred rents and lease market valuation liability | | (103 | ) | | (58 | ) |
| Deferred income taxes and investment tax credits, net | | 162 |
| | 138 |
|
| Asset impairments | | 6 |
| | 28 |
|
| Gain on asset sales | | (17 | ) | | — |
|
| Accrued compensation and retirement benefits | | 14 |
| | (24 | ) |
| Pension trust contribution | | (209 | ) | | — |
|
| Commodity derivative transactions, net | | (53 | ) | | (60 | ) |
| Cash collateral, net | | 17 |
| | (40 | ) |
| Decrease (increase) in operating assets- | | | | |
| Receivables | | — |
| | (36 | ) |
| Materials and supplies | | (56 | ) | | 50 |
|
| Prepayments and other current assets | | 19 |
| | 12 |
|
| Increase (decrease) in operating liabilities- | | | | |
| Accounts payable | | 243 |
| | (124 | ) |
| Accrued taxes | | (167 | ) | | (29 | ) |
| Other | | 7 |
| | 21 |
|
| Net cash provided from operating activities | | 219 |
| | 182 |
|
| | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | |
| New financing- | | | | |
| Long-term debt | | 82 |
| | 247 |
|
| Short-term borrowings, net | | — |
| | 530 |
|
| Redemptions and repayments- | | | | |
| Long-term debt | | (140 | ) | | (472 | ) |
| Other | | (6 | ) | | (11 | ) |
| Net cash provided from (used for) financing activities | | (64 | ) | | 294 |
|
| | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | |
| Property additions | | (303 | ) | | (334 | ) |
| Proceeds from assets sale | | 17 |
| | — |
|
| Sales of investment securities held in trusts | | 109 |
| | 513 |
|
| Purchases of investment securities held in trusts | | (127 | ) | | (545 | ) |
| Loans to affiliated companies, net | | 155 |
| | (93 | ) |
| Other | | (6 | ) | | (20 | ) |
| Net cash used for investing activities | | (155 | ) | | (479 | ) |
| | | | | |
| Net change in cash and cash equivalents | | — |
| | (3 | ) |
| Cash and cash equivalents at beginning of period | | 7 |
| | 9 |
|
| Cash and cash equivalents at end of period | | $ | 7 |
| | $ | 6 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
7
OHIO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 360,203 | | | $ | 415,437 | | | $ | 724,034 | | | $ | 895,362 | |
| Excise and gross receipts tax collections | | | 24,941 | | | | 23,949 | | | | 53,136 | | | | 52,424 | |
| | | | | | | | | | | | | |
| Total revenues | | | 385,144 | | | | 439,386 | | | | 777,170 | | | | 947,786 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power from affiliates | | | 69,134 | | | | 134,050 | | | | 162,396 | | | | 287,727 | |
| Purchased power from non-affiliates | | | 62,667 | | | | 78,826 | | | | 123,046 | | | | 173,057 | |
| Other operating expenses | | | 110,778 | | | | 88,275 | | | | 212,240 | | | | 177,130 | |
| Provision for depreciation | | | 22,470 | | | | 22,014 | | | | 44,346 | | | | 43,894 | |
| Amortization of regulatory assets, net | | | 2,405 | | | | 9,424 | | | | 3,179 | | | | 38,769 | |
| General taxes | | | 45,592 | | | | 43,362 | | | | 95,018 | | | | 90,854 | |
| | | | | | | | | | | | | |
| Total expenses | | | 313,046 | | | | 375,951 | | | | 640,225 | | | | 811,431 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 72,098 | | | | 63,435 | | | | 136,945 | | | | 136,355 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | | 5,043 | | | | 6,309 | | | | 9,351 | | | | 11,553 | |
| Miscellaneous income (expense) | | | (477 | ) | | | 1,295 | | | | (187 | ) | | | 1,003 | |
| Interest expense | | | (22,011 | ) | | | (22,155 | ) | | | (44,156 | ) | | | (44,465 | ) |
| Capitalized interest | | | 510 | | | | 295 | | | | 841 | | | | 503 | |
| | | | | | | | | | | | | |
| Total other expense | | | (16,935 | ) | | | (14,256 | ) | | | (34,151 | ) | | | (31,406 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 55,163 | | | | 49,179 | | | | 102,794 | | | | 104,949 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 16,538 | | | | 11,856 | | | | 34,029 | | | | 31,465 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | | 38,625 | | | | 37,323 | | | | 68,765 | | | | 73,484 | |
| | | | | | | | | | | | | | | | | |
| Income attributable to noncontrolling interest | | | 114 | | | | 130 | | | | 230 | | | | 262 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 38,511 | | | $ | 37,193 | | | $ | 68,535 | | | $ | 73,222 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 38,625 | | | $ | 37,323 | | | $ | 68,765 | | | $ | 73,484 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 1,122 | | | | 322 | | | | 1,461 | | | | 4,337 | |
| Increase in unrealized gain on available-for-sale securities | | | 1,591 | | | | 520 | | | | 1,569 | | | | 811 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 2,713 | | | | 842 | | | | 3,030 | | | | 5,148 | |
| Income tax expense (benefit) related to other | | | | | | | | | | | | | | | | |
| comprehensive income | | | 386 | | | | (26 | ) | | | (1,110 | ) | | | 667 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 2,327 | | | | 868 | | | | 4,140 | | | | 4,481 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | 40,952 | | | | 38,191 | | | | 72,905 | | | | 77,965 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO | | | | | | | | | | | | | | | | |
NONCONTROLLING INTEREST | | | 114 | | | | 130 | | | | 230 | | | | 262 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 40,838 | | | $ | 38,061 | | | $ | 72,675 | | | $ | 77,703 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 | | 2012 | | 2011 |
| | | | | | | | | |
| STATEMENTS OF INCOME | | | | | | | | |
| REVENUES: | | | | | | | | |
| Electric sales | | $ | 364 |
| | $ | 360 |
| | $ | 723 |
| | $ | 724 |
|
| Excise and gross receipts tax collections | | 24 |
| | 25 |
| | 51 |
| | 53 |
|
| Total revenues | | 388 |
| | 385 |
| | 774 |
| | 777 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | |
| Purchased power from affiliates | | 38 |
| | 69 |
| | 90 |
| | 163 |
|
| Purchased power from non-affiliates | | 66 |
| | 63 |
| | 136 |
| | 123 |
|
| Other operating expenses | | 119 |
| | 106 |
| | 240 |
| | 202 |
|
| Provision for depreciation | | 25 |
| | 23 |
| | 49 |
| | 46 |
|
| Amortization of regulatory assets, net | | 15 |
| | 2 |
| | 15 |
| | 3 |
|
| General taxes | | 46 |
| | 46 |
| | 96 |
| | 95 |
|
| Total operating expenses | | 309 |
| | 309 |
| | 626 |
| | 632 |
|
| | | | | | | | | |
| OPERATING INCOME | | 79 |
| | 76 |
| | 148 |
| | 145 |
|
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Investment income | | 5 |
| | 4 |
| | 9 |
| | 9 |
|
| Interest expense | | (23 | ) | | (22 | ) | | (45 | ) | | (44 | ) |
| Capitalized interest | | 1 |
| | 1 |
| | 2 |
| | 1 |
|
| Total other expense | | (17 | ) | | (17 | ) | | (34 | ) | | (34 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 62 |
| | 59 |
| | 114 |
| | 111 |
|
| | | | | | | | | |
| INCOME TAXES | | 21 |
| | 18 |
| | 42 |
| | 38 |
|
| | | | | | | | | |
| NET INCOME | | $ | 41 |
|
| $ | 41 |
|
| $ | 72 |
|
| $ | 73 |
|
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 41 |
| | $ | 41 |
| | $ | 72 |
| | $ | 73 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE LOSS: | | | | | | | | |
| Pensions and OPEB prior service costs | | (7 | ) | | (7 | ) | | (17 | ) | | (15 | ) |
| Change in unrealized gain on available-for-sale securities | | — |
| | 2 |
| | — |
| | 2 |
|
| Other comprehensive loss | | (7 | ) | | (5 | ) | | (17 | ) | | (13 | ) |
| Income tax benefits on other comprehensive loss | | (4 | ) | | (3 | ) | | (9 | ) | | (7 | ) |
| Other comprehensive loss, net of tax | | (3 | ) | | (2 | ) | | (8 | ) | | (6 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | $ | 38 |
| | $ | 39 |
| | $ | 64 |
| | $ | 67 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
8
OHIO EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 176 | | | $ | 420,489 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $3,564 in 2011 and $4,086 in 2010 | | | 159,393 | | | | 176,591 | |
| Associated companies | | | 68,709 | | | | 118,135 | |
| Other | | | 32,798 | | | | 12,232 | |
| Notes receivable from associated companies | | | 95,884 | | | | 16,957 | |
| Prepayments and other | | | 35,339 | | | | 6,393 | |
| | | | | | | |
| | | | 392,299 | | | | 750,797 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 3,176,455 | | | | 3,136,623 | |
| Less — Accumulated provision for depreciation | | | 1,230,570 | | | | 1,207,745 | |
| | | | | | | |
| | | | 1,945,885 | | | | 1,928,878 | |
| Construction work in progress | | | 66,656 | | | | 45,103 | |
| | | | | | | |
| | | | 2,012,541 | | | | 1,973,981 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lease obligation bonds | | | 177,835 | | | | 190,420 | |
| Nuclear plant decommissioning trusts | | | 133,354 | | | | 127,017 | |
| Other | | | 92,440 | | | | 95,563 | |
| | | | | | | |
| | | | 403,629 | | | | 413,000 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Regulatory assets | | | 392,580 | | | | 400,322 | |
| Pension assets | | | 62,612 | | | | 28,596 | |
| Property taxes | | | 71,331 | | | | 71,331 | |
| Unamortized sale and leaseback costs | | | 27,628 | | | | 30,126 | |
| Other | | | 19,041 | | | | 17,634 | |
| | | | | | | |
| | | | 573,192 | | | | 548,009 | |
| | | | | | | |
| | | $ | 3,381,661 | | | $ | 3,685,787 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 1,429 | | | $ | 1,419 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | — | | | | 142,116 | |
| Other | | | 166 | | | | 320 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 94,821 | | | | 99,421 | |
| Other | | | 41,417 | | | | 29,639 | |
| Accrued taxes | | | 69,364 | | | | 78,707 | |
| Accrued interest | | | 25,374 | | | | 25,382 | |
| Other | | | 79,795 | | | | 74,947 | |
| | | | | | | |
| | | | 312,366 | | | | 451,951 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholder’s equity- | | | | | | | | |
| Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding | | | 783,871 | | | | 951,866 | |
| Accumulated other comprehensive loss | | | (174,936 | ) | | | (179,076 | ) |
| Retained earnings | | | 110,156 | | | | 141,621 | |
| | | | | | | |
| Total common stockholder’s equity | | | 719,091 | | | | 914,411 | |
| Noncontrolling interest | | | 5,313 | | | | 5,680 | |
| | | | | | | |
| Total equity | | | 724,404 | | | | 920,091 | |
| Long-term debt and other long-term obligations | | | 1,151,720 | | | | 1,152,134 | |
| | | | | | | |
| | | | 1,876,124 | | | | 2,072,225 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 749,687 | | | | 696,410 | |
| Accumulated deferred investment tax credits | | | 9,439 | | | | 10,159 | |
| Retirement benefits | | | 183,345 | | | | 183,712 | |
| Asset retirement obligations | | | 69,164 | | | | 74,456 | |
| Other | | | 181,536 | | | | 196,874 | |
| | | | | | | |
| | | | 1,193,171 | | | | 1,161,611 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 3,381,661 | | | $ | 3,685,787 | |
| | | | | | | |
| | The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements. |
9
OHIO EDISON COMPANY
|
| | | | | | | | |
| (In millions, except share amounts) | | June 30,
2012 | | December 31,
2011 |
| ASSETS | | | | |
| CURRENT ASSETS: | | | | |
| Cash and cash equivalents | | $ | — |
| | $ | 26 |
|
| Receivables- | | | | |
| Customers, net of allowance for uncollectible accounts of $4 in 2012 and 2011 | | 173 |
| | 163 |
|
| Affiliated companies | | 51 |
| | 86 |
|
| Other | | 15 |
| | 41 |
|
| Notes receivable from affiliated companies | | 245 |
| | 181 |
|
| Prepayments and other | | 14 |
| | 17 |
|
| | | 498 |
| | 514 |
|
| UTILITY PLANT: | | | | |
| In service | | 3,443 |
| | 3,358 |
|
| Less — Accumulated provision for depreciation | | 1,294 |
| | 1,267 |
|
| | | 2,149 |
| | 2,091 |
|
| Construction work in progress | | 87 |
| | 91 |
|
| | | 2,236 |
| | 2,182 |
|
| OTHER PROPERTY AND INVESTMENTS: | | | | |
| Investment in lease obligation bonds | | 148 |
| | 163 |
|
| Nuclear plant decommissioning trusts | | 141 |
| | 137 |
|
| Other | | 91 |
| | 90 |
|
| | | 380 |
| | 390 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | |
| Regulatory assets | | 340 |
| | 363 |
|
| Property taxes | | 80 |
| | 81 |
|
| Unamortized sale and leaseback costs | | 23 |
| | 25 |
|
| Other | | 23 |
| | 19 |
|
| | | 466 |
| | 488 |
|
| | | $ | 3,580 |
| | $ | 3,574 |
|
| LIABILITIES AND CAPITALIZATION | | | | |
| CURRENT LIABILITIES: | | | | |
| Currently payable long-term debt | | $ | 3 |
| | $ | 2 |
|
| Accounts payable- | | | | |
| Affiliated companies | | 90 |
| | 119 |
|
| Other | | 37 |
| | 35 |
|
| Accrued taxes | | 76 |
| | 88 |
|
| Accrued interest | | 28 |
| | 25 |
|
| Other | | 69 |
| | 79 |
|
| | | 303 |
| | 348 |
|
| CAPITALIZATION: | | | | |
| Common stockholder's equity- | | | | |
| Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding | | 721 |
| | 747 |
|
| Accumulated other comprehensive income | | 46 |
| | 54 |
|
| Accumulated deficit | | (12 | ) | | (84 | ) |
| Total common stockholder's equity | | 755 |
| | 717 |
|
| Noncontrolling interest | | 5 |
| | 5 |
|
| Total equity | | 760 |
| | 722 |
|
| Long-term debt and other long-term obligations | | 1,157 |
| | 1,155 |
|
| | | 1,917 |
| | 1,877 |
|
| NONCURRENT LIABILITIES: | | | | |
| Accumulated deferred income taxes | | 799 |
| | 787 |
|
| Retirement benefits | | 211 |
| | 213 |
|
| Asset retirement obligations | | 74 |
| | 71 |
|
| Other | | 276 |
| | 278 |
|
| | | 1,360 |
| | 1,349 |
|
| COMMITMENTS AND CONTINGENCIES (Note 9) | |
| |
|
| | | $ | 3,580 |
| | $ | 3,574 |
|
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 68,765 | | | $ | 73,484 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 44,346 | | | | 43,894 | |
| Amortization of regulatory assets, net | | | 3,179 | | | | 38,769 | |
| Purchased power cost recovery reconciliation | | | (8,584 | ) | | | (1,514 | ) |
| Amortization of lease costs | | | (4,696 | ) | | | (4,619 | ) |
| Deferred income taxes and investment tax credits, net | | | 62,216 | | | | 4,964 | |
| Accrued compensation and retirement benefits | | | (8,328 | ) | | | (16,154 | ) |
| Accrued regulatory obligations | | | (3,309 | ) | | | (2,309 | ) |
| Cash collateral from (to) suppliers, net | | | (850 | ) | | | 1,215 | |
| Pension trust contribution | | | (27,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 80,968 | | | | 49,250 | |
| Prepayments and other current assets | | | (28,947 | ) | | | 5,072 | |
| Decrease in operating liabilities- | | | | | | | | |
| Accounts payable | | | (22,253 | ) | | | (57,208 | ) |
| Accrued taxes | | | (9,360 | ) | | | (25,685 | ) |
| Other | | | 4,261 | | | | (114 | ) |
| | | | | | | |
| Net cash provided from operating activities | | | 150,408 | | | | 109,045 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (707 | ) | | | (2,957 | ) |
| Short-term borrowings, net | | | (142,270 | ) | | | (93,017 | ) |
| Common stock dividend payments | | | (268,000 | ) | | | (250,000 | ) |
| Other | | | (2,340 | ) | | | (881 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (413,317 | ) | | | (346,855 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (78,894 | ) | | | (71,698 | ) |
| Leasehold improvement payments from associated companies | | | — | | | | 18,375 | |
| Sales of investment securities held in trusts | | | 19,595 | | | | 59,804 | |
| Purchases of investment securities held in trusts | | | (25,547 | ) | | | (64,063 | ) |
| Loans to associated companies, net | | | (78,927 | ) | | | 12,420 | |
| Cash investments | | | 11,962 | | | | 11,774 | |
| Other | | | (5,593 | ) | | | (1,298 | ) |
| | | | | | | |
| Net cash used for investing activities | | | (157,404 | ) | | | (34,686 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (420,313 | ) | | | (272,496 | ) |
| Cash and cash equivalents at beginning of period | | | 420,489 | | | | 324,175 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 176 | | | $ | 51,679 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
10
OHIO EDISON COMPANY
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)CASH FLOWS
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 202,148 | | | $ | 280,180 | | | $ | 408,890 | | | $ | 592,677 | |
| Excise tax collections | | | 15,706 | | | | 15,495 | | | | 33,851 | | | | 33,068 | |
| | | | | | | | | | | | | |
| Total revenues | | | 217,854 | | | | 295,675 | | | | 442,741 | | | | 625,745 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power from affiliates | | | 36,040 | | | | 99,422 | | | | 82,208 | | | | 208,815 | |
| Purchased power from non-affiliates | | | 23,099 | | | | 32,651 | | | | 41,319 | | | | 70,049 | |
| Other operating expenses | | | 31,625 | | | | 28,937 | | | | 66,661 | | | | 60,172 | |
| Provision for depreciation | | | 18,488 | | | | 18,336 | | | | 36,914 | | | | 36,447 | |
| Amortization of regulatory assets, net | | | 18,166 | | | | 30,807 | | | | 41,536 | | | | 75,946 | |
| General taxes | | | 36,954 | | | | 28,840 | | | | 77,166 | | | | 67,329 | |
| | | | | | | | | | | | | |
| Total expenses | | | 164,372 | | | | 238,993 | | | | 345,804 | | | | 518,758 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 53,482 | | | | 56,682 | | | | 96,937 | | | | 106,987 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | | 5,637 | | | | 6,605 | | | | 12,234 | | | | 14,152 | |
| Miscellaneous income | | | 1,038 | | | | 675 | | | | 1,674 | | | | 1,257 | |
| Interest expense | | | (32,135 | ) | | | (33,262 | ) | | | (65,213 | ) | | | (66,883 | ) |
| Capitalized interest | | | 36 | | | | 7 | | | | 63 | | | | 33 | |
| | | | | | | | | | | | | |
| Total other expense | | | (25,424 | ) | | | (25,975 | ) | | | (51,242 | ) | | | (51,441 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 28,058 | | | | 30,707 | | | | 45,695 | | | | 55,546 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 6,209 | | | | 8,785 | | | | 10,645 | | | | 19,628 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | | 21,849 | | | | 21,922 | | | | 35,050 | | | | 35,918 | |
| | | | | | | | | | | | | | | | | |
| Income attributable to noncontrolling interest | | | 309 | | | | 366 | | | | 675 | | | | 785 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 21,540 | | | $ | 21,556 | | | $ | 34,375 | | | $ | 35,133 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 21,849 | | | $ | 21,922 | | | $ | 35,050 | | | $ | 35,918 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits (charges) | | | 2,975 | | | | 3,228 | | | | 5,942 | | | | (19,357 | ) |
| Income tax expense (benefit) related to other comprehensive income | | | 860 | | | | 976 | | | | 398 | | | | (7,301 | ) |
| | | | | | | | | | | | | |
| Other comprehensive income (loss), net of tax | | | 2,115 | | | | 2,252 | | | | 5,544 | | | | (12,056 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | 23,964 | | | | 24,174 | | | | 40,594 | | | | 23,862 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 309 | | | | 366 | | | | 675 | | | | 785 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 23,655 | | | $ | 23,808 | | | $ | 39,919 | | | $ | 23,077 | |
| | | | | | | | | | | | | |
|
| | | | | | | | |
| | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 |
| | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
| Net Income | | $ | 72 |
| | $ | 73 |
|
| Adjustments to reconcile net income to net cash from operating activities- | | | | |
| Provision for depreciation | | 49 |
| | 46 |
|
| Amortization of regulatory assets, net | | 15 |
| | 3 |
|
| Amortization of lease costs | | (5 | ) | | (5 | ) |
| Deferred income taxes and investment tax credits, net | | 22 |
| | 66 |
|
| Accrued compensation and retirement benefits | | (26 | ) | | (18 | ) |
| Pension trust contribution | | — |
| | (27 | ) |
| Decrease (increase) in operating assets- | | | | |
| Receivables | | 54 |
| | 81 |
|
| Prepayments and other current assets | | 3 |
| | (29 | ) |
| Decrease in operating liabilities- | | | | |
| Accounts payable | | (27 | ) | | (22 | ) |
| Accrued taxes | | (12 | ) | | (9 | ) |
| Accrued interest | | 3 |
| | — |
|
| Other | | (2 | ) | | (9 | ) |
| Net cash provided from operating activities | | 146 |
| | 150 |
|
| | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | |
| Redemptions and Repayments- | | | | |
| Long-term debt | | (1 | ) | | (1 | ) |
| Short-term borrowings, net | | — |
| | (142 | ) |
| Common stock dividend payments | | (25 | ) | | (268 | ) |
| Other | | (1 | ) | | (2 | ) |
| Net cash used for financing activities | | (27 | ) | | (413 | ) |
| | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | |
| Property additions | | (86 | ) | | (79 | ) |
| Sales of investment securities held in trusts | | 57 |
| | 20 |
|
| Purchases of investment securities held in trusts | | (62 | ) | | (25 | ) |
| Loans to affiliated companies, net | | (63 | ) | | (79 | ) |
| Cash investments | | 13 |
| | 12 |
|
| Other | | (4 | ) | | (6 | ) |
| Net cash used for investing activities | | (145 | ) | | (157 | ) |
| | | | | |
| Net change in cash and cash equivalents | | (26 | ) | | (420 | ) |
| Cash and cash equivalents at beginning of period | | 26 |
| | 420 |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | — |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
11
THE CLEVELAND ELECTRIC ILLUMINATING
10
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
CONSOLIDATED BALANCE SHEETS
(Unaudited)| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 244 | | | $ | 238 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $2,801 in 2011 and $4,589 in 2010 | | | 97,997 | | | | 183,744 | |
| Associated companies | | | 32,348 | | | | 77,047 | |
| Other | | | 13,476 | | | | 11,544 | |
| Notes receivable from associated companies | | | 71,911 | | | | 23,236 | |
| Materials and supplies, at average cost | | | 13,784 | | | | 398 | |
| Prepayments and other | | | 6,431 | | | | 3,258 | |
| | | | | | | |
| | | | 236,191 | | | | 299,465 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,417,031 | | | | 2,396,893 | |
| Less — Accumulated provision for depreciation | | | 944,379 | | | | 932,246 | |
| | | | | | | |
| | | | 1,472,652 | | | | 1,464,647 | |
| Construction work in progress | | | 59,281 | | | | 38,610 | |
| | | | | | | |
| | | | 1,531,933 | | | | 1,503,257 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 286,745 | | | | 340,029 | |
| Other | | | 10,048 | | | | 10,074 | |
| | | | | | | |
| | | | 296,793 | | | | 350,103 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,688,521 | | | | 1,688,521 | |
| Regulatory assets | | | 320,337 | | | | 370,403 | |
| Pension assets | | | 14,652 | | | | — | |
| Property taxes | | | 80,614 | | | | 80,614 | |
| Other | | | 12,884 | | | | 11,486 | |
| | | | | | | |
| | | | 2,117,008 | | | | 2,151,024 | |
| | | | | | | |
| | | $ | 4,181,925 | | | $ | 4,303,849 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 188 | | | $ | 161 | |
| Short-term borrowings from associated companies | | | 23,303 | | | | 105,996 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 51,001 | | | | 32,020 | |
| Other | | | 18,700 | | | | 14,947 | |
| Accrued taxes | | | 83,265 | | | | 84,668 | |
| Accrued interest | | | 18,551 | | | | 18,555 | |
| Other | | | 38,685 | | | | 44,569 | |
| | | | | | | |
| | | | 233,693 | | | | 300,916 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholder’s equity- | | | | | | | | |
| Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding | | | 887,053 | | | | 887,087 | |
| Accumulated other comprehensive loss | | | (147,643 | ) | | | (153,187 | ) |
| Retained earnings | | | 539,280 | | | | 568,906 | |
| | | | | | | |
| Total common stockholder’s equity | | | 1,278,690 | | | | 1,302,806 | |
| Noncontrolling interest | | | 15,195 | | | | 18,017 | |
| | | | | | | |
| Total equity | | | 1,293,885 | | | | 1,320,823 | |
| Long-term debt and other long-term obligations | | | 1,831,023 | | | | 1,852,530 | |
| | | | | | | |
| | | | 3,124,908 | | | | 3,173,353 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 640,059 | | | | 622,771 | |
| Accumulated deferred investment tax credits | | | 10,574 | | | | 10,994 | |
| Retirement benefits | | | 76,010 | | | | 95,654 | |
| Other | | | 96,681 | | | | 100,161 | |
| | | | | | | |
| | | | 823,324 | | | | 829,580 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 4,181,925 | | | $ | 4,303,849 | |
| | | | | | | |
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 | | 2012 | | 2011 |
| | | | | | | | | |
| STATEMENTS OF INCOME | | | | | | | | |
| REVENUES: | | | | | | | | |
| Electric sales | | $ | 476 |
| | $ | 577 |
| | $ | 954 |
| | $ | 1,211 |
|
| Excise tax collections | | 8 |
| | 11 |
| | 18 |
| | 24 |
|
| Total revenues | | 484 |
| | 588 |
| | 972 |
| | 1,235 |
|
| | | | | | | | | |
| OPERATING EXPENSES: | | | | | | | | |
| Purchased power | | 254 |
| | 328 |
| | 518 |
| | 698 |
|
| Other operating expenses | | 81 |
| | 73 |
| | 162 |
| | 153 |
|
| Provision for depreciation | | 32 |
| | 28 |
| | 62 |
| | 54 |
|
| Amortization of regulatory assets, net | | 8 |
| | 40 |
| | 28 |
| | 122 |
|
| General taxes | | 12 |
| | 15 |
| | 27 |
| | 33 |
|
| Total operating expenses | | 387 |
| | 484 |
| | 797 |
| | 1,060 |
|
| | | | | | | | | |
| OPERATING INCOME | | 97 |
| | 104 |
| | 175 |
| | 175 |
|
| | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | |
| Miscellaneous income | | 1 |
| | 3 |
| | 2 |
| | 5 |
|
| Interest expense | | (30 | ) | | (31 | ) | | (61 | ) | | (61 | ) |
| Capitalized interest | | 1 |
| | 1 |
| | 1 |
| | 1 |
|
| Total other expense | | (28 | ) | | (27 | ) | | (58 | ) | | (55 | ) |
| | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 69 |
| | 77 |
| | 117 |
| | 120 |
|
| | | | | | | | | |
| INCOME TAXES | | 30 |
| | 32 |
| | 52 |
| | 52 |
|
| | | | | | | | | |
| NET INCOME | | $ | 39 |
| | $ | 45 |
| | $ | 65 |
| | $ | 68 |
|
| | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | |
| | | | | | | | | |
| NET INCOME | | $ | 39 |
| | $ | 45 |
| | $ | 65 |
| | $ | 68 |
|
| | | | | | | | | |
| OTHER COMPREHENSIVE LOSS: | | | | | | | | |
| Pensions and OPEB prior service costs | | (6 | ) | | (6 | ) | | (12 | ) | | (12 | ) |
| Other comprehensive loss | | (6 | ) | | (6 | ) | | (12 | ) | | (12 | ) |
| Income tax benefits on other comprehensive loss | | (3 | ) | | (3 | ) | | (7 | ) | | (5 | ) |
| Other comprehensive loss, net of tax | | (3 | ) | | (3 | ) | | (5 | ) | | (7 | ) |
| | | | | | | | | |
| COMPREHENSIVE INCOME | | $ | 36 |
| | $ | 42 |
| | $ | 60 |
| | $ | 61 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
12
THE CLEVELAND ELECTRIC ILLUMINATING
11
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 35,050 | | | $ | 35,918 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 36,914 | | | | 36,447 | |
| Amortization of regulatory assets, net | | | 41,536 | | | | 75,946 | |
| Deferred income taxes and investment tax credits, net | | | 17,221 | | | | (18,083 | ) |
| Accrued compensation and retirement benefits | | | 5,421 | | | | 5,421 | |
| Accrued regulatory obligations | | | (2,001 | ) | | | (444 | ) |
| Cash collateral from suppliers, net | | | — | | | | 685 | |
| Pension trust contribution | | | (35,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 140,455 | | | | 51,757 | |
| Prepayments and other current assets | | | (17,469 | ) | | | 5,392 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 10,135 | | | | (34,488 | ) |
| Accrued taxes | | | (346 | ) | | | (11,317 | ) |
| Other | | | (4,436 | ) | | | 2,023 | |
| | | | | | | |
| Net cash provided from operating activities | | | 227,480 | | | | 149,257 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (74 | ) | | | (54 | ) |
| Short-term borrowings, net | | | (104,228 | ) | | | (136,013 | ) |
| Common stock dividend payments | | | (64,000 | ) | | | (100,000 | ) |
| Other | | | (5,239 | ) | | | (3,367 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (173,541 | ) | | | (239,434 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (52,743 | ) | | | (44,373 | ) |
| Loans to associated companies, net | | | (48,676 | ) | | | 2,322 | |
| Redemptions of lessor notes | | | 53,283 | | | | 48,608 | |
| Other | | | (5,797 | ) | | | (2,365 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (53,933 | ) | | | 4,192 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 6 | | | | (85,985 | ) |
| Cash and cash equivalents at beginning of period | | | 238 | | | | 86,230 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 244 | | | $ | 245 | |
| | | | | | | |
|
| | | | | | | | |
| (In millions, except share amounts) | | June 30,
2012 | | December 31,
2011 |
| ASSETS | | | | |
| CURRENT ASSETS: | | | | |
| Receivables- | | | | |
| Customers, net of allowance for uncollectible accounts of $3 in 2012 and 2011 | | $ | 227 |
| | $ | 235 |
|
| Affiliated companies | | 12 |
| | — |
|
| Other | | 23 |
| | 17 |
|
| Prepaid taxes | | 108 |
| | 33 |
|
| Other | | 22 |
| | 19 |
|
| | | 392 |
| | 304 |
|
| UTILITY PLANT: | | | | |
| In service | | 5,067 |
| | 4,872 |
|
| Less — Accumulated provision for depreciation | | 1,779 |
| | 1,743 |
|
| | | 3,288 |
| | 3,129 |
|
| Construction work in progress | | 125 |
| | 227 |
|
| | | 3,413 |
| | 3,356 |
|
| OTHER PROPERTY AND INVESTMENTS: | | | | |
| Nuclear fuel disposal trust | | 227 |
| | 219 |
|
| Nuclear plant decommissioning trusts | | 196 |
| | 193 |
|
| Other | | 2 |
| | 2 |
|
| | | 425 |
| | 414 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | |
| Goodwill | | 1,811 |
| | 1,811 |
|
| Regulatory assets | | 523 |
| | 408 |
|
| Other | | 33 |
| | 32 |
|
| | | 2,367 |
| | 2,251 |
|
| | | $ | 6,597 |
| | $ | 6,325 |
|
| LIABILITIES AND CAPITALIZATION | | | | |
| CURRENT LIABILITIES: | | | | |
| Currently payable long-term debt | | $ | 35 |
| | $ | 34 |
|
| Short-term borrowings- | | | | |
| Affiliated companies | | 338 |
| | 259 |
|
| Other | | 80 |
| | — |
|
| Accounts payable- | | | | |
| Affiliated companies | | 16 |
| | 19 |
|
| Other | | 101 |
| | 101 |
|
| Accrued compensation and benefits | | 33 |
| | 41 |
|
| Customer deposits | | 24 |
| | 24 |
|
| Accrued interest | | 18 |
| | 18 |
|
| Other | | 21 |
| | 36 |
|
| | | 666 |
| | 532 |
|
| CAPITALIZATION: | | | | |
| Common stockholder's equity- | | | | |
| Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding | | 136 |
| | 136 |
|
| Other paid-in capital | | 2,011 |
| | 2,011 |
|
| Accumulated other comprehensive income | | 34 |
| | 39 |
|
| Retained earnings | | 136 |
| | 121 |
|
| Total common stockholder's equity | | 2,317 |
| | 2,307 |
|
| Long-term debt and other long-term obligations | | 1,720 |
| | 1,736 |
|
| | | 4,037 |
| | 4,043 |
|
| NONCURRENT LIABILITIES: | | | | |
| Accumulated deferred income taxes | | 917 |
| | 859 |
|
| Power purchase contract liability | | 270 |
| | 147 |
|
| Nuclear fuel disposal costs | | 197 |
| | 197 |
|
| Retirement benefits | | 163 |
| | 170 |
|
| Asset retirement obligations | | 119 |
| | 115 |
|
| Other | | 228 |
| | 262 |
|
| | | 1,894 |
| | 1,750 |
|
| COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | |
| |
|
| | | $ | 6,597 |
| | $ | 6,325 |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
13
JERSEY CENTRAL POWER & LIGHT COMPANY
THE TOLEDO EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)CASH FLOWS
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 93,048 | | | $ | 114,691 | | | $ | 199,373 | | | $ | 240,122 | |
| Excise tax collections | | | 6,270 | | | | 6,059 | | | | 13,572 | | | | 13,100 | |
| | | | | | | | | | | | | |
| Total revenues | | | 99,318 | | | | 120,750 | | | | 212,945 | | | | 253,222 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power from affiliates | | | 17,037 | | | | 47,106 | | | | 52,554 | | | | 101,725 | |
| Purchased power from non-affiliates | | | 16,114 | | | | 15,223 | | | | 30,102 | | | | 33,713 | |
| Other operating expenses | | | 32,549 | | | | 25,499 | | | | 69,136 | | | | 51,044 | |
| Provision for depreciation | | | 7,959 | | | | 8,013 | | | | 15,890 | | | | 15,963 | |
| Deferral of regulatory assets, net | | | (7,054 | ) | | | (1,800 | ) | | | (18,532 | ) | | | (10,299 | ) |
| General taxes | | | 12,438 | | | | 12,282 | | | | 26,890 | | | | 25,743 | |
| | | | | | | | | | | | | |
| Total expenses | | | 79,043 | | | | 106,323 | | | | 176,040 | | | | 217,889 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 20,275 | | | | 14,427 | | | | 36,905 | | | | 35,333 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Investment income | | | 2,599 | | | | 5,057 | | | | 5,521 | | | | 8,857 | |
| Miscellaneous income (expense) | | | 396 | | | | (945 | ) | | | (1,233 | ) | | | (2,351 | ) |
| Interest expense | | | (10,415 | ) | | | (10,455 | ) | | | (20,858 | ) | | | (20,942 | ) |
| Capitalized interest | | | 135 | | | | 80 | | | | 237 | | | | 158 | |
| | | | | | | | | | | | | |
| Total other expense | | | (7,285 | ) | | | (6,263 | ) | | | (16,333 | ) | | | (14,278 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 12,990 | | | | 8,164 | | | | 20,572 | | | | 21,055 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 1,429 | | | | 948 | | | | 3,164 | | | | 6,330 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | | 11,561 | | | | 7,216 | | | | 17,408 | | | | 14,725 | |
| | | | | | | | | | | | | | | | | |
| Income attributable to noncontrolling interest | | | 2 | | | | 2 | | | | 4 | | | | 5 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EARNINGS AVAILABLE TO PARENT | | $ | 11,559 | | | $ | 7,214 | | | $ | 17,404 | | | $ | 14,720 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 11,561 | | | $ | 7,216 | | | $ | 17,408 | | | $ | 14,725 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 575 | | | | 714 | | | | 1,167 | | | | 1,010 | |
| Increase (decrease) in unrealized gain on available-for-sale securities | | | 754 | | | | (330 | ) | | | 2,059 | | | | 39 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 1,329 | | | | 384 | | | | 3,226 | | | | 1,049 | |
| Income tax expense related to other comprehensive income | | | 351 | | | | 65 | | | | 685 | | | | 235 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 978 | | | | 319 | | | | 2,541 | | | | 814 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | | 12,539 | | | | 7,535 | | | | 19,949 | | | | 15,539 | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 2 | | | | 2 | | | | 4 | | | | 5 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME AVAILABLE TO PARENT | | $ | 12,537 | | | $ | 7,533 | | | $ | 19,945 | | | $ | 15,534 | |
| | | | | | | | | | | | | |
|
| | | | | | | | |
| | | Six Months
Ended June 30 |
| (In millions) | | 2012 | | 2011 |
| | | | | |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | |
| Net Income | | $ | 65 |
| | $ | 68 |
|
| Adjustments to reconcile net income to net cash from operating activities- | | | | |
| Provision for depreciation | | 62 |
| | 54 |
|
| Amortization of regulatory assets, net | | 28 |
| | 122 |
|
| Deferred purchased power and other costs | | (75 | ) | | (71 | ) |
| Deferred income taxes and investment tax credits, net | | 64 |
| | 55 |
|
| Accrued compensation and retirement benefits | | (27 | ) | | (11 | ) |
| Pension trust contribution | | — |
| | (105 | ) |
| Decrease (increase) in operating assets- | | | | |
| Receivables | | (10 | ) | | 58 |
|
| Prepaid taxes | | (75 | ) | | (125 | ) |
| Increase (decrease) in operating liabilities- | | | | |
| Accounts payable | | (2 | ) | | 14 |
|
| Accrued taxes | | (14 | ) | | (1 | ) |
| Other | | 7 |
| | — |
|
| Net cash provided from operating activities | | 23 |
| | 58 |
|
| | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | | | |
| New Financing- | | | | |
| Short-term borrowings, net | | 159 |
| | 411 |
|
| Redemptions and Repayments- | | | | |
| Long-term debt | | (16 | ) | | (15 | ) |
| Common stock dividend payments | | (50 | ) | | (500 | ) |
| Other | | — |
| | (1 | ) |
| Net cash provided from (used for) financing activities | | 93 |
| | (105 | ) |
| | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | |
| Property additions | | (102 | ) | | (98 | ) |
| Loans to affiliated companies, net | | — |
| | 161 |
|
| Sales of investment securities held in trusts | | 165 |
| | 376 |
|
| Purchases of investment securities held in trusts | | (172 | ) | | (386 | ) |
| Other | | (7 | ) | | (6 | ) |
| Net cash provided from (used for) investing activities | | (116 | ) | | 47 |
|
| | | | | |
| Net change in cash and cash equivalents | | — |
| | — |
|
| Cash and cash equivalents at beginning of period | | — |
| | — |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | — |
|
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
14
THE TOLEDO EDISON COMPANY
13
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 12 | | | $ | 149,262 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $1,142 in 2011 and $1 in 2010 | | | 45,931 | | | | 29 | |
| Associated companies | | | 48,340 | | | | 31,777 | |
| Other, net of allowance for uncollectible accounts of $339 in 2011 and $330 in 2010 | | | 5,272 | | | | 18,464 | |
| Notes receivable from associated companies | | | 128,815 | | | | 96,765 | |
| Prepayments and other | | | 12,052 | | | | 2,306 | |
| | | | | | | |
| | | | 240,422 | | | | 298,603 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 955,002 | | | | 947,203 | |
| Less — Accumulated provision for depreciation | | | 453,517 | | | | 446,401 | |
| | | | | | | |
| | | | 501,485 | | | | 500,802 | |
| Construction work in progress | | | 17,386 | | | | 12,604 | |
| | | | | | | |
| | | | 518,871 | | | | 513,406 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Investment in lessor notes | | | 82,153 | | | | 103,872 | |
| Nuclear plant decommissioning trusts | | | 79,018 | | | | 75,558 | |
| Other | | | 1,448 | | | | 1,492 | |
| | | | | | | |
| | | | 162,619 | | | | 180,922 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 500,576 | | | | 500,576 | |
| Regulatory assets | | | 89,112 | | | | 72,059 | |
| Pension assets | | | 24,603 | | | | — | |
| Property taxes | | | 24,990 | | | | 24,990 | |
| Other | | | 42,341 | | | | 23,750 | |
| | | | | | | |
| | | | 681,622 | | | | 621,375 | |
| | | | | | | |
| | | $ | 1,603,534 | | | $ | 1,614,306 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 188 | | | $ | 199 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 22,144 | | | | 17,168 | |
| Other | | | 12,524 | | | | 7,351 | |
| Accrued taxes | | | 23,699 | | | | 24,401 | |
| Accrued interest | | | 5,933 | | | | 5,931 | |
| Lease market valuation liability | | | 36,900 | | | | 36,900 | |
| Other | | | 18,060 | | | | 23,145 | |
| | | | | | | |
| | | | 119,448 | | | | 115,095 | |
| | | | | | | |
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 | | | 178,157 | | | | 178,182 | |
| Accumulated other comprehensive loss | | | (46,642 | ) | | | (49,183 | ) |
| Retained earnings | | | 100,937 | | | | 117,534 | |
| | | | | | | |
| Total common stockholder’s equity | | | 379,462 | | | | 393,543 | |
| Noncontrolling interest | | | 2,593 | | | | 2,589 | |
| | | | | | | |
| Total equity | | | 382,055 | | | | 396,132 | |
| Long-term debt and other long-term obligations | | | 600,524 | | | | 600,493 | |
| | | | | | | |
| | | | 982,579 | | | | 996,625 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 168,429 | | | | 132,019 | |
| Accumulated deferred investment tax credits | | | 5,715 | | | | 5,930 | |
| Retirement benefits | | | 51,764 | | | | 71,486 | |
| Asset retirement obligations | | | 29,737 | | | | 28,762 | |
| Lease market valuation liability | | | 180,850 | | | | 199,300 | |
| Other | | | 65,012 | | | | 65,089 | |
| | | | | | | |
| | | | 501,507 | | | | 502,586 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 1,603,534 | | | $ | 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
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 17,408 | | | $ | 14,725 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 15,890 | | | | 15,963 | |
| Deferral of regulatory assets, net | | | (18,532 | ) | | | (10,299 | ) |
| Deferred rents and lease market valuation liability | | | (43,851 | ) | | | (42,264 | ) |
| Deferred income taxes and investment tax credits, net | | | 41,457 | | | | 16,503 | |
| Accrued compensation and retirement benefits | | | 1,085 | | | | 2,600 | |
| Accrued regulatory obligations | | | (1,193 | ) | | | (632 | ) |
| Pension trust contribution | | | (45,000 | ) | | | — | |
| Cash collateral from (to) suppliers, net | | | (14 | ) | | | 343 | |
| Increase (decrease) in operating assets- | | | | | | | | |
| Receivables | | | (48,807 | ) | | | 52,754 | |
| Prepayments and other current assets | | | (9,758 | ) | | | 3,608 | |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 3,661 | | | | (61,195 | ) |
| Accrued taxes | | | (701 | ) | | | (4,007 | ) |
| Other | | | 5,771 | | | | (8,960 | ) |
| | | | | | | |
| Net cash used for operating activities | | | (82,584 | ) | | | (20,861 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (105 | ) | | | (111 | ) |
| Short-term borrowings, net | | | — | | | | (225,975 | ) |
| Common stock dividend payments | | | (34,000 | ) | | | (130,000 | ) |
| Other | | | (1,742 | ) | | | (112 | ) |
| | | | | | | |
| Net cash used for financing activities | | | (35,847 | ) | | | (356,198 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (17,386 | ) | | | (20,237 | ) |
| Leasehold improvement payments from associated companies | | | — | | | | 32,829 | |
| Loans to associated companies, net | | | (32,050 | ) | | | (10,818 | ) |
| Redemptions of lessor notes | | | 21,739 | | | | 20,485 | |
| Sales of investment securities held in trusts | | | 28,401 | | | | 106,814 | |
| Purchases of investment securities held in trusts | | | (30,050 | ) | | | (107,978 | ) |
| Other | | | (1,473 | ) | | | (2,905 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (30,819 | ) | | | 18,190 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (149,250 | ) | | | (358,869 | ) |
| Cash and cash equivalents at beginning of period | | | 149,262 | | | | 436,712 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 12 | | | $ | 77,843 | |
| | | | | | | |
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 | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 576,977 | | | $ | 709,606 | | | $ | 1,211,000 | | | $ | 1,400,998 | |
| Excise tax collections | | | 11,120 | | | | 11,012 | | | | 23,607 | | | | 23,364 | |
| | | | | | | | | | | | | |
| Total revenues | | | 588,097 | | | | 720,618 | | | | 1,234,607 | | | | 1,424,362 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power | | | 328,463 | | | | 410,470 | | | | 698,631 | | | | 824,486 | |
| Other operating expenses | | | 78,603 | | | | 75,177 | | | | 164,682 | | | | 170,837 | |
| Provision for depreciation | | | 26,773 | | | | 27,093 | | | | 52,087 | | | | 55,064 | |
| Amortization of regulatory assets, net | | | 40,046 | | | | 81,326 | | | | 121,633 | | | | 150,774 | |
| General taxes | | | 15,115 | | | | 14,902 | | | | 32,526 | | | | 31,338 | |
| | | | | | | | | | | | | |
| Total expenses | | | 489,000 | | | | 608,968 | | | | 1,069,559 | | | | 1,232,499 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 99,097 | | | | 111,650 | | | | 165,048 | | | | 191,863 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Miscellaneous income | | | 3,554 | | | | 1,649 | | | | 5,464 | | | | 3,482 | |
| Interest expense | | | (31,125 | ) | | | (30,041 | ) | | | (61,782 | ) | | | (59,464 | ) |
| Capitalized interest | | | 618 | | | | 156 | | | | 1,045 | | | | 289 | |
| | | | | | | | | | | | | |
| Total other expense | | | (26,953 | ) | | | (28,236 | ) | | | (55,273 | ) | | | (55,693 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 72,144 | | | | 83,414 | | | | 109,775 | | | | 136,170 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 30,383 | | | | 33,521 | | | | 48,461 | | | | 57,051 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 41,761 | | | $ | 49,893 | | | $ | 61,314 | | | $ | 79,119 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 41,761 | | | $ | 49,893 | | | $ | 61,314 | | | $ | 79,119 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 4,290 | | | | 4,135 | | | | 8,511 | | | | 20,063 | |
| Unrealized gain on derivative hedges | | | 69 | | | | 69 | | | | 138 | | | | 138 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 4,359 | | | | 4,204 | | | | 8,649 | | | | 20,201 | |
| Income tax expense related to other comprehensive income | | | 1,612 | | | | 1,441 | | | | 3,202 | | | | 7,999 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 2,747 | | | | 2,763 | | | | 5,447 | | | | 12,202 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 44,508 | | | $ | 52,656 | | | $ | 66,761 | | | $ | 91,321 | |
| | | | | | | | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
17
JERSEY CENTRAL POWER & LIGHT COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 42 | | | $ | 4 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $3,306 in 2011 and $3,769 in 2010 | | | 259,313 | | | | 323,044 | |
| Associated companies | | | 66,069 | | | | 53,780 | |
| Other | | | 25,580 | | | | 26,119 | |
| Notes receivable — associated companies | | | 16,288 | | | | 177,228 | |
| Prepaid taxes | | | 135,679 | | | | 10,889 | |
| Other | | | 15,421 | | | | 12,654 | |
| | | | | | | |
| | | | 518,392 | | | | 603,718 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 4,589,369 | | | | 4,562,781 | |
| Less — Accumulated provision for depreciation | | | 1,682,577 | | | | 1,656,939 | |
| | | | | | | |
| | | | 2,906,792 | | | | 2,905,842 | |
| Construction work in progress | | | 112,573 | | | | 63,535 | |
| | | | | | | |
| | | | 3,019,365 | | | | 2,969,377 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear fuel disposal trust | | | 212,419 | | | | 207,561 | |
| Nuclear plant decommissioning trusts | | | 190,422 | | | | 181,851 | |
| Other | | | 2,118 | | | | 2,104 | |
| | | | | | | |
| | | | 404,959 | | | | 391,516 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 1,810,936 | | | | 1,810,936 | |
| Regulatory assets | | | 469,490 | | | | 513,395 | |
| Other | | | 34,028 | | | | 27,938 | |
| | | | | | | |
| | | | 2,314,454 | | | | 2,352,269 | |
| | | | | | | |
| | | $ | 6,257,170 | | | $ | 6,316,880 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 33,315 | | | $ | 32,402 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 360,917 | | | | — | |
| Other | | | 50,000 | | | | — | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 56,544 | | | | 28,571 | |
| Other | | | 159,720 | | | | 158,442 | |
| Accrued compensation and benefits | | | 35,578 | | | | 35,232 | |
| Customer deposits | | | 23,684 | | | | 23,385 | |
| Accrued taxes | | | 1,346 | | | | 2,509 | |
| Accrued interest | | | 18,059 | | | | 18,111 | |
| Other | | | 13,487 | | | | 22,263 | |
| | | | | | | |
| | | | 752,650 | | | | 320,915 | |
| | | | | | | |
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 | | | 2,008,847 | | | | 2,508,874 | |
| Accumulated other comprehensive loss | | | (248,095 | ) | | | (253,542 | ) |
| Retained earnings | | | 288,484 | | | | 227,170 | |
| | | | | | | |
| Total common stockholder’s equity | | | 2,185,520 | | | | 2,618,786 | |
| Long-term debt and other long-term obligations | | | 1,754,582 | | | | 1,769,849 | |
| | | | | | | |
| | | | 3,940,102 | | | | 4,388,635 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 761,844 | | | | 715,527 | |
| Power purchase contract liability | | | 239,943 | | | | 233,492 | |
| Nuclear fuel disposal costs | | | 196,868 | | | | 196,768 | |
| Retirement benefits | | | 71,711 | | | | 182,364 | |
| Asset retirement obligations | | | 111,831 | | | | 108,297 | |
| Other | | | 182,221 | | | | 170,882 | |
| | | | | | | |
| | | | 1,564,418 | | | | 1,607,330 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | | $ | 6,257,170 | | | $ | 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)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 61,314 | | | $ | 79,119 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 52,087 | | | | 55,064 | |
| Amortization of regulatory assets, net | | | 121,633 | | | | 150,774 | |
| Deferred purchased power and other costs | | | (70,998 | ) | | | (67,664 | ) |
| Deferred income taxes and investment tax credits, net | | | 51,222 | | | | (1,425 | ) |
| Accrued compensation and retirement benefits | | | 1,319 | | | | 2,608 | |
| Cash collateral paid, net | | | (235 | ) | | | (23,400 | ) |
| Pension trust contribution | | | (105,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 58,466 | | | | (46,788 | ) |
| Prepaid taxes | | | (124,790 | ) | | | (111,968 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 13,856 | | | | 11,924 | |
| Accrued taxes | | | (1,167 | ) | | | 10,368 | |
| Other | | | 612 | | | | (6,446 | ) |
| | | | | | | |
| Net cash provided from operating activities | | | 58,319 | | | | 52,166 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | 410,917 | | | | 57,850 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (14,671 | ) | | | (13,830 | ) |
| Common stock dividend payments | | | — | | | | (90,000 | ) |
| Equity payment to parent | | | (500,000 | ) | | | — | |
| Other | | | (1,452 | ) | | | — | |
| | | | | | | |
| Net cash used for financing activities | | | (105,206 | ) | | | (45,980 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (98,153 | ) | | | (80,727 | ) |
| Loans to associated companies, net | | | 160,940 | | | | 85,049 | |
| Sales of investment securities held in trusts | | | 375,885 | | | | 281,242 | |
| Purchases of investment securities held in trusts | | | (385,448 | ) | | | (289,454 | ) |
| Other | | | (6,299 | ) | | | (2,224 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | 46,925 | | | | (6,114 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | 38 | | | | 72 | |
| Cash and cash equivalents at beginning of period | | | 4 | | | | 27 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 42 | | | $ | 99 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
19
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 265,363 | | | $ | 422,030 | | | $ | 603,779 | | | $ | 873,590 | |
| Gross receipts tax collections | | | 14,601 | | | | 20,629 | | | | 33,401 | | | | 42,196 | |
| | | | | | | | | | | | | |
| Total revenues | | | 279,964 | | | | 442,659 | | | | 637,180 | | | | 915,786 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power from affiliates | | | 34,935 | | | | 149,000 | | | | 84,824 | | | | 310,080 | |
| Purchased power from non-affiliates | | | 100,836 | | | | 85,276 | | | | 253,879 | | | | 177,204 | |
| Other operating expenses | | | 50,075 | | | | 90,151 | | | | 97,307 | | | | 192,134 | |
| Provision for depreciation | | | 12,766 | | | | 13,440 | | | | 25,189 | | | | 26,198 | |
| Amortization of regulatory assets, net | | | 22,167 | | | | 48,589 | | | | 54,261 | | | | 97,389 | |
| General taxes | | | 17,152 | | | | 19,894 | | | | 39,302 | | | | 41,634 | |
| | | | | | | | | | | | | |
| Total expenses | | | 237,931 | | | | 406,350 | | | | 554,762 | | | | 844,639 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 42,033 | | | | 36,309 | | | | 82,418 | | | | 71,147 | |
| | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Interest income | | | 13 | | | | 880 | | | | 106 | | | | 2,097 | |
| Miscellaneous income | | | 915 | | | | 1,381 | | | | 1,885 | | | | 3,554 | |
| Interest expense | | | (13,130 | ) | | | (13,002 | ) | | | (26,187 | ) | | | (26,775 | ) |
| Capitalized interest | | | 228 | | | | 159 | | | | 375 | | | | 285 | |
| | | | | | | | | | | | | |
| Total other expense | | | (11,974 | ) | | | (10,582 | ) | | | (23,821 | ) | | | (20,839 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 30,059 | | | | 25,727 | | | | 58,597 | | | | 50,308 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 13,281 | | | | 8,618 | | | | 19,232 | | | | 20,884 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 16,778 | | | $ | 17,109 | | | $ | 39,365 | | | $ | 29,424 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 16,778 | | | $ | 17,109 | | | $ | 39,365 | | | $ | 29,424 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 2,227 | | | | 2,162 | | | | 4,190 | | | | 11,871 | |
| Unrealized gain on derivative hedges | | | 84 | | | | 84 | | | | 168 | | | | 168 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 2,311 | | | | 2,246 | | | | 4,358 | | | | 12,039 | |
| Income tax expense related to other comprehensive income | | | 869 | | | | 724 | | | | 1,632 | | | | 4,901 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 1,442 | | | | 1,522 | | | | 2,726 | | | | 7,138 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 18,220 | | | $ | 18,631 | | | $ | 42,091 | | | $ | 36,562 | |
| | | | | | | | | | | | | |
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)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 157 | | | $ | 243,220 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $3,087 in 2011 and $3,868 in 2010 | | | 143,820 | | | | 178,522 | |
| Associated companies | | | 12,849 | | | | 24,920 | |
| Other | | | 16,437 | | | | 13,007 | |
| Notes receivable from associated companies | | | 10,432 | | | | 11,028 | |
| Prepaid taxes | | | 27,083 | | | | 343 | |
| Other | | | 1,443 | | | | 2,289 | |
| | | | | | | |
| | | | 212,221 | | | | 473,329 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,266,437 | | | | 2,247,853 | |
| Less — Accumulated provision for depreciation | | | 859,055 | | | | 846,003 | |
| | | | | | | |
| | | | 1,407,382 | | | | 1,401,850 | |
| Construction work in progress | | | 42,604 | | | | 23,663 | |
| | | | | | | |
| | | | 1,449,986 | | | | 1,425,513 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 301,188 | | | | 289,328 | |
| Other | | | 840 | | | | 884 | |
| | | | | | | |
| | | | 302,028 | | | | 290,212 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 416,499 | | | | 416,499 | |
| Regulatory assets | | | 341,488 | | | | 295,856 | |
| Power purchase contract asset | | | 65,861 | | | | 111,562 | |
| Other | | | 54,587 | | | | 31,699 | |
| | | | | | | |
| | | | 878,435 | | | | 855,616 | |
| | | | | | | |
| | | $ | 2,842,670 | | | $ | 3,044,670 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 28,760 | | | $ | 28,760 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 238,399 | | | | 124,079 | |
| Other | | | 50,000 | | | | — | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 24,377 | | | | 33,942 | |
| Other | | | 48,262 | | | | 29,862 | |
| Accrued taxes | | | 12,844 | | | | 60,856 | |
| Accrued interest | | | 16,011 | | | | 16,114 | |
| Other | | | 29,605 | | | | 29,278 | |
| | | | | | | |
| | | | 448,258 | | | | 322,891 | |
| | | | | | | |
CAPITALIZATION: | | | | | | | | |
| Common stockholder’s equity- | | | | | | | | |
| Common stock, without par value, authorized 900,000 shares, 740,905 and 859,500 shares outstanding, respectively | | | 842,023 | | | | 1,197,076 | |
| Accumulated other comprehensive loss | | | (139,657 | ) | | | (142,383 | ) |
| Retained earnings | | | 46,772 | | | | 32,406 | |
| | | | | | | |
| Total common stockholder’s equity | | | 749,138 | | | | 1,087,099 | |
| Long-term debt and other long-term obligations | | | 704,486 | | | | 718,860 | |
| | | | | | | |
| | | | 1,453,624 | | | | 1,805,959 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 494,716 | | | | 473,009 | |
| Accumulated deferred investment tax credits | | | 6,656 | | | | 6,866 | |
| Nuclear fuel disposal costs | | | 44,471 | | | | 44,449 | |
| Asset retirement obligations | | | 199,162 | | | | 192,659 | |
| Retirement benefits | | | 22,276 | | | | 29,121 | |
| Power purchase contract liability | | | 121,924 | | | | 116,027 | |
| Other | | | 51,583 | | | | 53,689 | |
| | | | | | | |
| | | | 940,788 | | | | 915,820 | |
| | | | | | | |
COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 2,842,670 | | | $ | 3,044,670 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
21
METROPOLITAN EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 39,365 | | | $ | 29,424 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 25,189 | | | | 26,198 | |
| Amortization of regulatory assets, net | | | 54,261 | | | | 97,389 | |
| Deferred costs recoverable as regulatory assets | | | (41,699 | ) | | | (38,358 | ) |
| Deferred income taxes and investment tax credits, net | | | 11,972 | | | | (12,079 | ) |
| Accrued compensation and retirement benefits | | | (510 | ) | | | (1,573 | ) |
| Cash collateral from suppliers, net | | | 174 | | | | 50 | |
| Pension trust contribution | | | (35,000 | ) | | | — | |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 46,240 | | | | (29,439 | ) |
| Prepaid taxes | | | (26,740 | ) | | | (31,246 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 5,148 | | | | 733 | |
| Accrued taxes | | | (47,676 | ) | | | 9,519 | |
| Accrued interest | | | (103 | ) | | | (1,277 | ) |
| Other | | | 10,903 | | | | 7,553 | |
| | | | | | | |
| Net cash provided from operating activities | | | 41,524 | | | | 56,894 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Short-term borrowings, net | | | 164,320 | | | | 17,898 | |
| Redemptions and Repayments- | | | | | | | | |
| Common stock | | | (150,000 | ) | | | — | |
| Long-term debt | | | (14,784 | ) | | | (100,000 | ) |
| Common stock dividend payments | | | (80,000 | ) | | | — | |
| Equity payment to parent | | | (150,000 | ) | | | — | |
| | | | | | | |
| Net cash used for financing activities | | | (230,464 | ) | | | (82,102 | ) |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (46,647 | ) | | | (54,405 | ) |
| Sales of investment securities held in trusts | | | 501,260 | | | | 376,610 | |
| Purchases of investment securities held in trusts | | | (506,220 | ) | | | (381,219 | ) |
| Loans to associated companies, net | | | 596 | | | | 85,943 | |
| Other | | | (3,112 | ) | | | (1,715 | ) |
| | | | | | | |
| Net cash provided from (used for) investing activities | | | (54,123 | ) | | | 25,214 | |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (243,063 | ) | | | 6 | |
| Cash and cash equivalents at beginning of period | | | 243,220 | | | | 120 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 157 | | | $ | 126 | |
| | | | | | | |
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 | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF INCOME | | | | | | | | | | | | | | | | |
REVENUES: | | | | | | | | | | | | | | | | |
| Electric sales | | $ | 238,942 | | | $ | 350,335 | | | $ | 547,258 | | | $ | 736,271 | |
| Gross receipts tax collections | | | 12,727 | | | | 16,162 | | | | 29,256 | | | | 33,686 | |
| | | | | | | | | | | | | |
| Total revenues | | | 251,669 | | | | 366,497 | | | | 576,514 | | | | 769,957 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | |
| Purchased power from affiliates | | | 54,635 | | | | 152,945 | | | | 102,119 | | | | 321,345 | |
| Purchased power from non-affiliates | | | 64,459 | | | | 86,829 | | | | 205,895 | | | | 178,252 | |
| Other operating expenses | | | 44,570 | | | | 67,070 | | | | 85,898 | | | | 139,464 | |
| Provision for depreciation | | | 15,770 | | | | 16,605 | | | | 30,343 | | | | 31,287 | |
| Amortization (deferral) of regulatory assets, net | | | 12,608 | | | | (10,522 | ) | | | 25,615 | | | | (20,488 | ) |
| General taxes | | | 14,665 | | | | 18,647 | | | | 35,401 | | | | 35,181 | |
| | | | | | | | | | | | | |
| Total expenses | | | 206,707 | | | | 331,574 | | | | 485,271 | | | | 685,041 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OPERATING INCOME | | | 44,962 | | | | 34,923 | | | | 91,243 | | | | 84,916 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | |
| Miscellaneous income | | | 644 | | | | 1,310 | | | | 669 | | | | 2,923 | |
| Interest expense | | | (17,361 | ) | | | (17,630 | ) | | | (34,595 | ) | | | (34,920 | ) |
| Capitalized interest | | | 41 | | | | 183 | | | | 63 | | | | 323 | |
| | | | | | | | | | | | | |
| Total other expense | | | (16,676 | ) | | | (16,137 | ) | | | (33,863 | ) | | | (31,674 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 28,286 | | | | 18,786 | | | | 57,380 | | | | 53,242 | |
| | | | | | | | | | | | | | | | | |
INCOME TAXES | | | 13,568 | | | | 5,812 | | | | 25,356 | | | | 22,969 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 14,718 | | | $ | 12,974 | | | $ | 32,024 | | | $ | 30,273 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 14,718 | | | $ | 12,974 | | | $ | 32,024 | | | $ | 30,273 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
OTHER COMPREHENSIVE INCOME: | | | | | | | | | | | | | | | | |
| Pension and other postretirement benefits | | | 1,890 | | | | 1,830 | | | | 3,475 | | | | 10,377 | |
| Unrealized gain on derivative hedges | | | 17 | | | | 16 | | | | 33 | | | | 32 | |
| | | | | | | | | | | | | |
| Other comprehensive income | | | 1,907 | | | | 1,846 | | | | 3,508 | | | | 10,409 | |
| Income tax expense related to other comprehensive income | | | 678 | | | | 483 | | | | 1,233 | | | | 3,767 | |
| | | | | | | | | | | | | |
| Other comprehensive income, net of tax | | | 1,229 | | | | 1,363 | | | | 2,275 | | | | 6,642 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
COMPREHENSIVE INCOME | | $ | 15,947 | | | $ | 14,337 | | | $ | 34,299 | | | $ | 36,915 | |
| | | | | | | | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
23
PENNSYLVANIA ELECTRIC COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
| | | | | | | | | |
| | | June 30, | | | December 31, | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
ASSETS | | | | | | | | |
| | | | | | | | | |
CURRENT ASSETS: | | | | | | | | |
| Cash and cash equivalents | | $ | 2 | | | $ | 5 | |
| Receivables- | | | | | | | | |
| Customers, net of allowance for uncollectible accounts of $2,856 in 2011 and $3,369 in 2010 | | | 121,511 | | | | 148,864 | |
| Associated companies | | | 65,989 | | | | 54,052 | |
| Other | | | 11,420 | | | | 11,314 | |
| Notes receivable from associated companies | | | 13,498 | | | | 14,404 | |
| Prepaid taxes | | | 26,372 | | | | 14,026 | |
| Other | | | 1,423 | | | | 1,592 | |
| | | | | | | |
| | | | 240,215 | | | | 244,257 | |
| | | | | | | |
UTILITY PLANT: | | | | | | | | |
| In service | | | 2,552,303 | | | | 2,532,629 | |
| Less — Accumulated provision for depreciation | | | 947,315 | | | | 935,259 | |
| | | | | | | |
| | | | 1,604,988 | | | | 1,597,370 | |
| Construction work in progress | | | 62,592 | | | | 30,505 | |
| | | | | | | |
| | | | 1,667,580 | | | | 1,627,875 | |
| | | | | | | |
OTHER PROPERTY AND INVESTMENTS: | | | | | | | | |
| Nuclear plant decommissioning trusts | | | 162,154 | | | | 152,928 | |
| Non-utility generation trusts | | | 126,786 | | | | 80,244 | |
| Other | | | 292 | | | | 297 | |
| | | | | | | |
| | | | 289,232 | | | | 233,469 | |
| | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | |
| Goodwill | | | 768,628 | | | | 768,628 | |
| Regulatory assets | | | 222,804 | | | | 163,407 | |
| Power purchase contract asset | | | 4,000 | | | | 5,746 | |
| Other | | | 15,272 | | | | 19,287 | |
| | | | | | | |
| | | | 1,010,704 | | | | 957,068 | |
| | | | | | | |
| | | $ | 3,207,731 | | | $ | 3,062,669 | |
| | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | |
| | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | |
| Currently payable long-term debt | | $ | 45,000 | | | $ | 45,000 | |
| Short-term borrowings- | | | | | | | | |
| Associated companies | | | 159,902 | | | | 101,338 | |
| Accounts payable- | | | | | | | | |
| Associated companies | | | 77,121 | | | | 35,626 | |
| Other | | | 29,217 | | | | 41,420 | |
| Accrued taxes | | | 3,397 | | | | 5,075 | |
| Accrued interest | | | 17,454 | | | | 17,378 | |
| Other | | | 23,280 | | | | 22,541 | |
| | | | | | | |
| | | | 355,371 | | | | 268,378 | |
| | | | | | | |
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 | | | 913,486 | | | | 913,519 | |
| Accumulated other comprehensive loss | | | (161,251 | ) | | | (163,526 | ) |
| Retained earnings | | | 23,017 | | | | 60,993 | |
| | | | | | | |
| Total common stockholder’s equity | | | 863,804 | | | | 899,538 | |
| Long-term debt and other long-term obligations | | | 1,072,417 | | | | 1,072,262 | |
| | | | | | | |
| | | | 1,936,221 | | | | 1,971,800 | |
| | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | |
| Accumulated deferred income taxes | | | 415,899 | | | | 371,877 | |
| Retirement benefits | | | 188,407 | | | | 187,621 | |
| Power purchase contract liability | | | 160,130 | | | | 116,972 | |
| Asset retirement obligations | | | 101,441 | | | | 98,132 | |
| Other | | | 50,262 | | | | 47,889 | |
| | | | | | | |
| | | | 916,139 | | | | 822,491 | |
| | | | | | | |
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | |
| | $ | 3,207,731 | | | $ | 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)
| | | | | | | | | |
| | | Six Months Ended | |
| | | June 30 | |
| (In thousands) | | 2011 | | | 2010 | |
| | | | | | | | | |
CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | | |
| Net Income | | $ | 32,024 | | | $ | 30,273 | |
| Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | |
| Provision for depreciation | | | 30,343 | | | | 31,287 | |
| Amortization (deferral) of regulatory assets, net | | | 25,615 | | | | (20,488 | ) |
| Deferred costs recoverable as regulatory assets | | | (38,291 | ) | | | (38,955 | ) |
| Deferred income taxes and investment tax credits, net | | | 46,687 | | | | 42,943 | |
| Accrued compensation and retirement benefits | | | 4,733 | | | | 4,216 | |
| Cash collateral paid, net | | | (1,276 | ) | | | (3,613 | ) |
| Decrease (increase) in operating assets- | | | | | | | | |
| Receivables | | | 19,561 | | | | 3,266 | |
| Prepaid taxes | | | (12,346 | ) | | | (37,504 | ) |
| Increase (decrease) in operating liabilities- | | | | | | | | |
| Accounts payable | | | 23,449 | | | | (4,603 | ) |
| Accrued taxes | | | (12,373 | ) | | | (1,339 | ) |
| Other | | | 13,153 | | | | 10,227 | |
| | | | | | | |
| Net cash provided from operating activities | | | 131,279 | | | | 15,710 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | |
| New Financing- | | | | | | | | |
| Long-term debt | | | 25,000 | | | | — | |
| Short-term borrowings, net | | | 58,564 | | | | 25,313 | |
| Redemptions and Repayments- | | | | | | | | |
| Long-term debt | | | (25,000 | ) | | | — | |
| Common stock dividend payments | | | (70,000 | ) | | | — | |
| Other | | | (1,353 | ) | | | 5 | |
| | | | | | | |
| Net cash provided from (used for) financing activities | | | (12,789 | ) | | | 25,318 | |
| | | | | | | |
| | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | |
| Property additions | | | (64,177 | ) | | | (58,293 | ) |
| Loans to associated companies, net | | | 906 | | | | 498 | |
| Sales of investment securities held in trusts | | | 265,223 | | | | 133,934 | |
| Purchases of investment securities held in trusts | | | (314,738 | ) | | | (113,067 | ) |
| Other | | | (5,707 | ) | | | (4,104 | ) |
| | | | | | | |
| Net cash used for investing activities | | | (118,493 | ) | | | (41,032 | ) |
| | | | | | | |
| | | | | | | | | |
| Net change in cash and cash equivalents | | | (3 | ) | | | (4 | ) |
| Cash and cash equivalents at beginning of period | | | 5 | | | | 14 | |
| | | | | | | |
| Cash and cash equivalents at end of period | | $ | 2 | | | $ | 10 | |
| | | | | | | |
The accompanying Combined Notes to the Consolidated Financial Statements are an integral part of these financial statements.
25
FIRSTENERGY CORP. AND SUBSIDIARIES
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
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| Regulatory Matters | |
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COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy
Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.
FE is a diversified energy holding 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,ME, PN, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL)FET), FES and its principal subsidiaries FGCO(FGCO and NGC,NGC), and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly-ownedwholly owned subsidiary of FirstEnergy (See Note 2, Merger).FirstEnergy. Accordingly, consolidated results of operations for the six months ended June 30, 2011, include just four months of Allegheny results.
FirstEnergy
The consolidated financial statements of FE, FES, OE and JCP&L include the accounts of entities in which a controlling financial interest is held, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or the result of an analysis that identifies FE or one of its subsidiaries follow GAAP and comply withas the related regulations, orders, policies and practices prescribed byprimary beneficiary of a VIE. Investments in which a controlling financial interest is not held are accounted for under the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. equity or cost method of accounting.
These unaudited interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes were prepared in accordance with GAAP forhave been condensed or omitted pursuant to such rules and regulations. These interim financial information. Accordingly, they do not includestatements 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, 2011.
The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair presentation of the information and footnotes required by GAAP for complete annual financial statements. 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.
These unaudited interim financial statements should be read
As described in conjunction with the financial statements and notes included in the combinedits Annual Report on Form 10-K for the year ended December 31, 2010 for FirstEnergy, FES and the Utility Registrants, as applicable. The2011, FE's consolidated unaudited financial statements of FirstEnergy, FES and each of the Utility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. six months ended June 30, 2011, were revised to reflect a purchase accounting measurement adjustment identified during the fourth quarter of 2011 that decreased goodwill and increased income tax expense by approximately $20 million.
As described in its Annual Report on Form 10-K for the year ended December 31, 2011, during the fourth quarter of 2011, FE elected to change its method of accounting relating to its defined benefit pension and OPEB plans to recognize the change in fair value of plan assets and net actuarial gains and losses immediately, and applied this change retrospectively. Generally, these gains and losses are measured annually as of December 31, and accordingly, will be recorded during the fourth quarter.
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 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
New Accounting Pronouncements
New accounting pronouncements 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’s earnings is reported in the Consolidated Statements of Income.
2. MERGER
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 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 | |
| | | | |
27
The 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 accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:
| | | | | |
| (In millions) | | | | |
| | | | | |
| Current assets | | $ | 1,494 | |
| Property, plant and equipment | | | 9,656 | |
| Investments | | | 138 | |
| Goodwill | | | 881 | |
| Other noncurrent assets | | | 1,347 | |
| Current liabilities | | | (716 | ) |
| Noncurrent liabilities | | | (3,452 | ) |
| Long-term debt and other long-term obligations | | | (4,994 | ) |
| | | | |
| | | $ | 4,354 | |
| | | | |
The allocation of purchase price in the table above reflects a refinement made during the quarter ended June 30, 2011 in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This resulted in an increase in noncurrent assets of approximately $85 million and decreases in current assets and goodwill of $15 million and $71 million, respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during the quarter ended March 31, 2011 was not significant. Further modifications to the purchase price allocation may occur as a result of continuing review of the assets acquired and liabilities assumed.
The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.
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 $881 million has been assigned 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 as of December 31, 2010 | | $ | 5,551 | | | $ | 24 | | | $ | — | | | $ | — | | | $ | 5,575 | |
| | | | | | | | | | | | | | | | | | | | | |
| Merger with Allegheny | | | — | | | | 881 | | | | — | | | | — | | | | 881 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance as of June 30, 2011 | | $ | 5,551 | | | $ | 905 | | | $ | — | | | $ | — | | | $ | 6,456 | |
| | | | | | | | | | | | | | | | |
28
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 contracts | | $ | 189 | | | 10 years |
| NUG contracts | | | 124 | | | 25 years |
| Coal supply contracts | | | 516 | | | 8 years |
| | | | | | | | |
| | | | 829 | | | | | |
| | | | | | | | | |
| Below market contracts: | | | | | | | | |
| NUG contracts | | | 143 | | | 13 years |
| Coal supply contracts | | | 83 | | | 7 years |
| Transportation contract | | | 35 | | | 8 years |
| | | | | | | | |
| | | | 261 | | | | | |
| | | | | | | | |
| | | | | | | | | |
| Net intangible assets | | $ | 568 | | | | | |
| | | | | | | | |
The fair value measurements of intangible assets and liabilities were 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 adjustment for these contracts is being amortized based on expected deliveries under each contract.
As of June 30, 2011, intangible assets on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the merger, include the following:
| | | | | |
| | | Intangible | |
| (In millions) | | Assets | |
| Purchase contract assets | | | | |
| NUG | | $ | 198 | |
| OVEC | | | 54 | |
| | | | |
| | | | 252 | |
| | | | | |
| Intangible assets | | | | |
| Coal contracts | | | 487 | |
| FES customer intangible assets | | | 129 | |
| Energy contracts | | | 105 | |
| | | | |
| | | | 721 | |
| | | | |
| | | | | |
| Total intangible assets | | $ | 973 | |
| | | | |
Acquired land easements and software with a fair value of $169 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2011.
In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $7 million ($5 million net of tax) and $7 million ($5 million net of tax) during the three months ended June 30, 2011 and 2010, respectively and approximately $89 million ($72 million net of tax) and $21 million ($15 million net of tax) during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. Merger transaction costs recognized in the first six months of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.
29
FirstEnergy also recorded approximately $10 million ($6 million net of tax) and $85 million ($66 million net of tax) in merger integration costs during the three and six months ended June 30 2011, respectively, 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 that 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) in the first quarter of 2011.
Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the periods subsequent to the February 25, 2011 merger date are as follows:
| | | | | | | | | |
| | April 1 – | | | February 26 – | |
| (In millions, except per share amounts) | | June 30, 2011 | | | June 30, 2011 | |
| | | | | | | | | |
Total revenues | | $ | 1,181 | | | $ | 1,618 | |
Earnings available to FirstEnergy Corp.(1) | | | 63 | | | | 17 | |
| | | | | | | | | |
Basic Earnings Per Share | | $ | 0.15 | | | $ | 0.04 | |
Diluted Earnings Per Share | | $ | 0.15 | | | $ | 0.04 | |
| | |
(1) | | Includes Allegheny’s after-tax merger costs of $4 million and $56 million, respectively. |
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. Combined pre-tax transaction costs incurred were approximately $7 million and $11 million in the three months ended June 30, 2011 and 2010, respectively, and approximately $90 million and $39 million in the six months ended June 30, 2011 and 2010, respectively. In addition, during the six months ended June 30, 2011, $85 million of pre-tax merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlementsyet effective are not expected to behave a material in future periods.effect on the financial statements of FE or its subsidiaries.
The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved or the future consolidated results of operations of the combined company.
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| (Pro forma amounts in millions, except | | June 30 | | | June 30 | |
| per share amounts) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | | | | | | | | | | | | | | | |
Revenues | | $ | 4,062 | | | $ | 4,401 | | | $ | 8,848 | | | $ | 9,086 | |
Earnings available to FirstEnergy | | $ | 186 | | | $ | 389 | | | $ | 323 | | | $ | 644 | |
| | | | | | | | | | | | | | | | | |
Basic Earnings Per Share | | $ | 0.44 | | | $ | 0.93 | | | $ | 0.77 | | | $ | 1.54 | |
| | | | | | | | | | | | | |
Diluted Earnings Per Share | | $ | 0.44 | | | $ | 0.93 | | | $ | 0.77 | | | $ | 1.53 | |
| | | | | | | | | | | | | |
30
3.2. EARNINGS PER SHARE
Basic earnings per share of common stock are computed using the weighted average number of actual common shares outstanding during the relevant 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 would be issuedcould result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
| | | | | | | | | | | | | | | | | |
| | Three Months | | | Six Months | |
| Reconciliation of Basic and Diluted Earnings per Share | | Ended June 30 | | | Ended June 30 | |
| of Common Stock | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions, except per share amounts) | |
| | | | | | | | | | | | | | | | | |
Earnings available to FirstEnergy Corp. | | $ | 181 | | | $ | 265 | | | $ | 231 | | | $ | 420 | |
| | | | | | | | | | | | | |
Weighted average number of basic shares outstanding(1) | | | 418 | | | | 304 | | | | 380 | | | | 304 | |
Assumed exercise of dilutive stock options and awards | | | 2 | | | | 1 | | | | 2 | | | | 1 | |
| | | | | | | | | | | | | |
Weighted average number of diluted shares outstanding(1) | | | 420 | | | | 305 | | | | 382 | | | | 305 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Basic earnings per share of common stock | | $ | 0.43 | | | $ | 0.87 | | | $ | 0.61 | | | $ | 1.38 | |
| | | | | | | | | | | | | |
Diluted earnings per share of common stock | | $ | 0.43 | | | $ | 0.87 | | | $ | 0.61 | | | $ | 1.37 | |
| | | | | | | | | | | | | |
15
|
| | | | | | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| Reconciliation of Basic and Diluted Earnings per Share of Common Stock | | 2012 | | 2011 | | 2012 | | 2011 |
| | | (In millions, except per share amounts) |
| | | | | | | | | |
| Weighted average number of basic shares outstanding | | 417 |
| | 418 |
| | 418 |
| | 380 |
|
Assumed exercise of dilutive stock options and awards(1) | | 2 |
| | 2 |
| | 1 |
| | 2 |
|
| Weighted average number of diluted shares outstanding | | 419 |
| | 420 |
| | 419 |
| | 382 |
|
| | | | | | | | | |
| Earnings Available to FirstEnergy Corp. | | $ | 187 |
| | $ | 203 |
| | $ | 493 |
| | $ | 255 |
|
| | | | | | | | | |
| Basic earnings per share of common stock | | $ | 0.45 |
| | $ | 0.48 |
| | $ | 1.18 |
| | $ | 0.67 |
|
| Diluted earnings per share of common stock | | $ | 0.45 |
| | $ | 0.48 |
| | $ | 1.18 |
| | $ | 0.67 |
|
| |
(1) | The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months and six months ended June 30, 2012 and 2011. |
3. PENSIONS AND OTHER POSTEMPLOYMENT 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. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pensions and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the six months ended June 30, 2012, FirstEnergy made a voluntary $600 million pre-tax contribution to its qualified pension plan.
The components of the consolidated net periodic cost for pensions and OPEB costs (including amounts capitalized) were as follows:
|
| | | | | | | | | | | | | | | | |
| Components of Net Periodic Benefit Costs (Credits) | | Pensions | | OPEB |
| For the Three Months Ended June 30, | | 2012 | | 2011 | | 2012 | | 2011 |
| | | (In millions) |
| Service cost | | $ | 40 |
| | $ | 34 |
| | $ | 3 |
| | $ | 3 |
|
| Interest cost | | 97 |
| | 96 |
| | 12 |
| | 12 |
|
| Expected return on plan assets | | (121 | ) | | (115 | ) | | (9 | ) | | (10 | ) |
| Amortization of prior service cost | | 3 |
| | 4 |
| | (51 | ) | | (51 | ) |
| Other adjustments (settlements, curtailments, etc) | | — |
| | — |
| | — |
| | — |
|
| Net periodic costs (credits) | | $ | 19 |
| | $ | 19 |
| | $ | (45 | ) | | $ | (46 | ) |
|
| | | | | | | | | | | | | | | | |
| Components of Net Periodic Benefit Costs (Credits) | | Pensions | | OPEB |
| For the Six Months Ended June 30, | | 2012 | | 2011 | | 2012 | | 2011 |
| | | (In millions) |
| Service cost | | $ | 80 |
| | $ | 63 |
| | $ | 6 |
| | $ | 6 |
|
| Interest cost | | 194 |
| | 180 |
| | 24 |
| | 23 |
|
| Expected return on plan assets | | (242 | ) | | (217 | ) | | (18 | ) | | (20 | ) |
| Amortization of prior service cost | | 6 |
| | 8 |
| | (102 | ) | | (99 | ) |
| Other adjustments (settlements, curtailments, etc) | | — |
| | 7 |
| | — |
| | — |
|
| Net periodic costs (credits) | | $ | 38 |
| | $ | 41 |
| | $ | (90 | ) | | $ | (90 | ) |
Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and its subsidiaries were as follows:
|
| | | | | | | | | | | | | | | | |
| Net Periodic Benefit Costs (Credits) | | Pensions | | OPEB |
| For the Three Months Ended June 30, | | 2012 | | 2011 | | 2012 | | 2011 |
| | | (In millions) |
| FE Consolidated | | $ | 14 |
| | $ | 14 |
| | $ | (32 | ) | | $ | (34 | ) |
| FES | | 11 |
| | 7 |
| | (8 | ) | | (9 | ) |
| OE | | (1 | ) | | (2 | ) | | (6 | ) | | (5 | ) |
| JCP&L | | (2 | ) | | (3 | ) | | (2 | ) | | (2 | ) |
|
| | | | | | | | | | | | | | | | |
| Net Periodic Benefit Costs (Credits) | | Pensions | | OPEB |
| For the Six Months Ended June 30, | | 2012 | | 2011 | | 2012 | | 2011 |
| | | (In millions) |
| FE Consolidated | | $ | 27 |
| | $ | 34 |
| | $ | (62 | ) | | $ | (66 | ) |
| FES | | 21 |
| | 14 |
| | (16 | ) | | (16 | ) |
| OE | | (2 | ) | | (4 | ) | | (11 | ) | | (11 | ) |
| JCP&L | | (3 | ) | | (5 | ) | | (4 | ) | | (5 | ) |
4. 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's tax return. During the second quarter of 2012, FirstEnergy reached a settlement with state authorities related to state apportionment factors in Pennsylvania on an intercompany asset sale, which favorably affected FirstEnergy's effective tax rate by $3 million in the three and six months ended June 30, 2012. Earlier in the year, the federal government issued further guidance related to the tax accounting of costs to repair and maintain fixed assets. This guidance provided a safe harbor method of tax accounting for the AE companies and allowed these companies to reduce their amount of unrecognized tax benefits by $21 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item, with no resulting impact to FirstEnergy's effective tax rate for the first six months of 2012. In the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy's effective tax rate in the three and six months ended June 30, 2011.
As of June 30, 2012, it is reasonably possible that approximately $42 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $7 million, if recognized, would affect FirstEnergy's effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.
FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. During the first six months of 2012 there were no material changes to the amount of accrued interest. The interest associated with the settlement of the claim in 2011 noted above favorably affected FirstEnergy's effective tax rate by $6 million in the first six months of 2011. During the first six months of 2011, there were no other material changes to the amount of accrued interest, except for a $6 million increase in accrued interest from the merger with AE in the first quarter of 2011. The net amount of interest accrued as of June 30, 2012 was $12 million, compared with $11 million as of December 31, 2011.
As a result of the non-deductible portion of merger transaction costs, FirstEnergy's effective tax rate was unfavorably impacted by $28 million in the first six months of 2011.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2008-2010, and additionally 2005-2007 for New Jersey. The IRS completed its audits of tax year 2008 in July 2010 and tax year 2009 in April 2011, with both tax years having one open item. Tax years 2010-2011 are under review by the IRS. Allegheny is currently under audit by the IRS for tax years 2009 and 2010. State tax returns for tax years 2008 through 2010 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. 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, results of operations, cash flow or liquidity.
5. VARIABLE INTEREST ENTITIES
FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary.
VIEs included in FirstEnergy’s consolidated financial statements for the second quarter of 2012 are: the PNBV and Shippingport capital trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; 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 and JCP&L's supply of BGS, of which $262 million was outstanding as of June 30, 2012; and special purpose limited liabilities companies of MP and PE created to issue environmental control bonds that were used to construct environmental control facilities, of which $503 million was outstanding as of June 30, 2012.
The caption noncontrolling interest within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. The change in noncontrolling interest within the Consolidated Balance Sheets during the six months ended June 30, 2012, was primarily due to net income attributable to noncontrolling interests of $1 million, offset by a $5 million distribution to owners.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.
Mining Operations
On October 18, 2011, a subsidiary of Gunvor Group, Ltd. purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. FEV retained a 33-1/3% equity ownership in the joint venture. Prior to the sale, FirstEnergy consolidated this joint venture since FEV was determined to be the primary beneficiary of the VIE. As a result of the sale, FEV was no longer determined to be the primary beneficiary and its retained 33-1/3% interest is subsequently accounted for using the equity method of accounting.
PATH-WV
PATH was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was 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 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 (PATH-Allegheny) 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 $31 million as of June 30, 2012.
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 applicable utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, ME, PN, PE, WP and MP, maintains 21 long-term power purchase agreements with NUG entities that were entered into pursuant to 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 three of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining three entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. One of JCP&L's NUG contracts, to which the scope exception was applied, expired during 2011.
Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the three contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended June 30, 2012, were $14 million, $27 million and $17 million for JCP&L, PE and WP, respectively and $26 million, $59 million and $33 million for the six months ended June 30, 2012, respectively. Purchased power costs related to the four contracts that may contain a variable interest that were held by JCP&L, PE and WP, respectively, during the three months ended June 30, 2011, were $55 million, $47 million, and $21 million, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively.
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 wherein WP may hold a variable interest, for which WP has taken the scope exception. As of June 30, 2012, WP’s reserve for this adverse purchase power commitment was $48 million, including a current liability of $11 million, and is being amortized over the life of the commitment.
Loss Contingencies
FirstEnergy has variable interests in certain sale and leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.
FES, OE and other FE subsidiaries are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of June 30, 2012:
|
| | | | | | | | | | | |
| | Maximum Exposure | | Discounted Lease Payments, net(1) | | Net Exposure |
| | (In millions) |
| FES | $ | 1,318 |
| | $ | 1,111 |
| | $ | 207 |
|
| OE | 574 |
| | 384 |
| | 190 |
|
| Other FE subsidiaries | 599 |
| | 333 |
| | 266 |
|
| |
(1) | The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.5 billion. |
6. FAIR VALUE MEASUREMENTS
RECURRING AND NONRECURRING FAIR VALUE MEASUREMENTS
On January 1, 2012, FirstEnergy adopted an amendment to the authoritative accounting guidance regarding fair value measurements. The amendment was applied prospectively and expanded disclosure requirements for fair value measurements, particularly for Level 3 measurements, among other changes.
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques for Level 2 and Level 3 are as follows:
|
| | |
| Level 1 | - | Quoted prices for identical instruments in active market |
| | | |
(1)Level 2 | - | Quoted prices for similar instruments in active market |
| | Includes 113 million shares issued to AE stockholders- | Quoted prices for the periods subsequentidentical or similar instruments in markets that are not active |
| - | Model-derived valuations for which all significant inputs are observable market data |
Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.
|
| | |
| Level 3 | - | Valuation inputs are unobservable and significant to the merger date. (See Note 2)fair value measurement |
4. FAIR VALUE MEASUREMENTS
(A) LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONSFirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by the Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs are as follows.
All borrowings
FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are subsequently adjusted to fair value using a mark-to-model methodology on a monthly basis, which approximates market. The primary inputs into the model, that are generally less observable from objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 7, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.
NUG contracts represent purchased power agreements with initial maturitiesthird-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value using a mark-to-model methodology on a quarterly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of less than onemarket prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on IntercontinentalExchange quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.
LCAPP contracts are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. LCAPP contracts are recorded at fair value using a mark-to-model methodology on a quarterly basis, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Quarterly pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices for the 2015/2016 delivery year and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2015/2016 delivery year are defineddeveloped through a simulation of future PJM RPM auctions. The capacity price forecast assumes a continuation of the current PJM RPM market design and is reflective of the regional peak demand growth and generation fleet additions and retirements that underlie FirstEnergy’s long-term energy price forecast. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.
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. There were no changes in valuation methodologies used as short-term financial instruments under GAAPof June 30, 2012 from those used as of December 31, 2011. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.
Transfers between levels are reported onrecognized at the Consolidated Balance Sheetsend of the reporting period. There were no transfers between levels during the six months ended June 30, 2012. The following tables set forth the recurring assets and liabilities that are accounted for at cost, which approximates their fair market value inby level within the caption “short-term borrowings”. fair value hierarchy.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FE CONSOLIDATED | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements | June 30, 2012 | December 31, 2011 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | (In millions) |
| Corporate debt securities | $ | — | | | $ | 1,636 | | | $ | — | | | 1,636 |
| | $ | — | | | $ | 1,544 | | | $ | — | | | $ | 1,544 |
|
| Derivative assets - commodity contracts | 4 | | | 337 | | | — | | | 341 |
| | — | | | 264 | | | — | | | 264 |
|
| Derivative assets - FTRs | — | | | — | | | 12 | | | 12 |
| | — | | | — | | | 1 | | | 1 |
|
| Derivative assets - interest rate swaps | — | | | 3 | | | — | | | 3 |
| | — | | | — | | | — | | | — |
|
Derivative assets - NUG contracts(1) | — | | | — | | | 9 | | | 9 |
| | — | | | — | | | 56 | | | 56 |
|
Equity securities(2) | 280 | | | — | | | — | | | 280 |
| | 259 | | | — | | | — | | | 259 |
|
| Foreign government debt securities | — | | | — | | | — | | | — |
| | — | | | 3 | | | — | | | 3 |
|
| U.S. government debt securities | — | | | 144 | | | — | | | 144 |
| | — | | | 148 | | | — | | | 148 |
|
| U.S. state debt securities | — | | | 308 | | | — | | | 308 |
| | — | | | 314 | | | — | | | 314 |
|
Other(3) | 63 | | | 128 | | | — | | | 191 |
| | 49 | | | 225 | | | — | | | 274 |
|
| Total assets | 347 | | | 2,556 | | | 21 | | | 2,924 |
| | 308 | |
| 2,498 | |
| 57 | | | 2,863 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | | | | | | | |
| Derivative liabilities - commodity contracts | (1 | ) | | (262 | ) | | — | | | (263 | ) | | — | | | (247 | ) | | — | | | (247 | ) |
| Derivative liabilities - FTRs | — | | | — | | | (9 | ) | | (9 | ) | | — | | | — | | | (23 | ) | | (23 | ) |
| Derivative liabilities - interest rate swaps | — | | | (23 | ) | | — | | | (23 | ) | | — | | | — | | | — | | | — |
|
Derivative liabilities - NUG contracts(1) | — | | | — | | | (302 | ) | | (302 | ) | | — | | | — | | | (349 | ) | | (349 | ) |
Derivative liabilities - LCAPP contracts(1) | — | | | — | | | (145 | ) | | (145 | ) | | — | | | — | | | — | | | — |
|
| Total liabilities | (1 | ) | | (285 | ) | | (456 | ) | | (742 | ) | | — | | | (247 | ) | | (372 | ) | | (619 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
Net assets (liabilities)(4) | $ | 346 | | | $ | 2,271 | | | $ | (435 | ) | | $ | 2,182 |
| | $ | 308 | | | $ | 2,251 | | | $ | (315 | ) | | $ | 2,244 |
|
| |
(1) | NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. |
| |
(2) | NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index. |
| |
(3) | Primarily consists of short-term cash investments. |
| |
(4) | Excludes $(7) million and $(52) million as of June 30, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. |
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the approximate fair value of NUG and related carrying amounts of long-term debtLCAPP contracts held by certain Utilities and other long-term obligationsFTRs held by FirstEnergy and classified as of Level 3 in the fair value hierarchy for the periods ended June 30, 20112012 and December 31, 2010:2011:
| | | | | | | | | | | | | | | | | |
| | | June 30, 2011 | | | December 31, 2010 | |
| | Carrying | | | Fair | | | Carrying | | | Fair | |
| | Value | | | Value | | | Value | | | Value | |
| | (In millions) | |
FirstEnergy(1) | | $ | 18,371 | | | $ | 19,436 | | | $ | 13,928 | | | $ | 14,845 | |
FES | | | 4,056 | | | | 4,310 | | | | 4,279 | | | | 4,403 | |
OE | | | 1,158 | | | | 1,367 | | | | 1,159 | | | | 1,321 | |
CEI | | | 1,831 | | | | 2,083 | | | | 1,853 | | | | 2,035 | |
TE | | | 600 | | | | 690 | | | | 600 | | | | 653 | |
JCP&L | | | 1,795 | | | | 2,008 | | | | 1,810 | | | | 1,962 | |
Met-Ed | | | 729 | | | | 828 | | | | 742 | | | | 821 | |
Penelec | | | 1,120 | | | | 1,231 | | | | 1,120 | | | | 1,189 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | NUG Contracts(1) | | LCAPP Contracts(1) | | FTRs |
| | Derivative Assets | | Derivative Liabilities | | Net | | Derivative Assets | | Derivative Liabilities | | Net | | Derivative Assets | | Derivative Liabilities | | Net |
| | | | | | | | | | | | | | |
| January 1, 2011 Balance | $ | 122 |
| | $ | (466 | ) | | $ | (344 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Realized gain (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrealized gain (loss) | (58 | ) | | (144 | ) | | (202 | ) | | — |
| | — |
| | — |
| | 2 |
| | (27 | ) | | (25 | ) |
| Purchases | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 13 |
| | (4 | ) | | 9 |
|
| Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Sales | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements | (7 | ) | | 261 |
| | 254 |
| | — |
| | — |
| | — |
| | (14 | ) | | 20 |
| | 6 |
|
| Transfers in (out) of Level 3 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (12 | ) | | (12 | ) |
| December 31, 2011 Balance | $ | 57 |
| | $ | (349 | ) | | $ | (292 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
| | $ | (23 | ) | | $ | (22 | ) |
| Realized gain (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrealized gain (loss) | (48 | ) | | (86 | ) | | (134 | ) | | — |
| | — |
| | — |
| | — |
| | (2 | ) | | (2 | ) |
| Purchases | — |
| | — |
| | — |
| | — |
| | (145 | ) | | (145 | ) | | 12 |
| | (9 | ) | | 3 |
|
| Issues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Sales | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements | — |
| | 133 |
| | 133 |
| | — |
| | — |
| | — |
| | (1 | ) | | 25 |
| | 24 |
|
| Transfers in (out) of Level 3 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| June 30, 2012 Balance | $ | 9 |
| | $ | (302 | ) | | $ | (293 | ) | | $ | — |
|
| $ | (145 | ) | | $ | (145 | ) | | $ | 12 |
| | $ | (9 | ) | | $ | 3 |
|
| | |
(1) | | Includes debt assumedChanges in the Allegheny merger (See Note 2) with a carrying value and a fair value of NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings. |
Level 3 Quantitative Information
The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:
|
| | | | | | | | | | | | | | | | |
| | | Fair Value as of June 30, 2012 (In millions) | | Valuation Technique | | Significant Input | | Range | | Weighted Average | | Units |
| FTRs | | $ | 3 |
| | Model | | RTO auction clearing prices | | ($3.60) to $4.90 | | $ | 0.70 |
| | Dollars/MWH |
| NUG Contracts | | $ | (293 | ) | | Model | | Generation Electricity regional prices | | 500 to 6,609,000 $49.50 to $84.90 | | 2,665,000 $63.70 |
| | MWH Dollars/MWH |
| LCAPP Contracts | | $ | (145 | ) | | Model | | Regional capacity prices | | $94.90 to $248.40 | | $183.90 | | Dollars/MW-Day |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FES | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements | June 30, 2012 | | December 31, 2011 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | (In millions) |
| Corporate debt securities | $ | — | | | $ | 1,057 | | | $ | — | | | $ | 1,057 | | | $ | — | | | $ | 1,010 | | | $ | — | | | $ | 1,010 | |
| Derivative assets - commodity contracts | 4 | | | 326 | | | — | | | 330 | | | — | | | 248 | | | — | | | 248 | |
| Derivative assets - FTRs | — | | | — | | | 8 | | | 8 | | | — | | | — | | | 1 | | | 1 | |
Equity securities(1) | 145 | | | — | | | — | | | 145 | | | 124 | | | — | | | — | | | 124 | |
| Foreign government debt securities | — | | | — | | | — | | | — | | | — | | | 3 | | | — | | | 3 | |
| U.S. government debt securities | — | | | 6 | | | — | | | 6 | | | — | | | 7 | | | — | | | 7 | |
| U.S. state debt securities | — | | | — | | | — | | | — | | | — | | | 5 | | | — | | | 5 | |
Other(2) | — | | | 48 | | | — | | | 48 | | | — | | | 132 | | | — | | | 132 | |
| Total assets | 149 | | | 1,437 | | | 8 | | | 1,594 | | | 124 | | | 1,405 | | | 1 | | | 1,530 | |
| | | | | | | | | | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
| Derivative liabilities - commodity contracts | (1 | ) | | (262 | ) | | — | | | (263 | ) | | — | | | (234 | ) | | — | | | (234 | ) |
| Derivative liabilities - FTRs | — | | | — | | | (6 | ) | | (6 | ) | | — | | | — | | | (7 | ) | | (7 | ) |
| Total liabilities | (1 | ) | | (262 | ) | | (6 | ) | | (269 | ) | | — | | | (234 | ) | | (7 | ) | | (241 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | $ | 148 | | | $ | 1,175 | | | $ | 2 | | | $ | 1,325 | | | $ | 124 | | | $ | 1,171 | | | $ | (6 | ) | | $ | 1,289 | |
| |
(1) | NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index. |
| |
(2) | Primarily consists of short-term cash investments. |
| |
(3) | Excludes $(6) million and $(58) millionas of June 30, 2012 and December 31, 2011, respectively, of $4,530 millionreceivables, payables, taxes and $4,127 million, respectively.accrued income associated with the financial instruments reflected within the fair value table. |
Rollforward of Level 3 Measurements
The fair valuesfollowing table provides a reconciliation of long-term debt and other long-term obligations reflectchanges in the presentfair value of FTRs held by FES and classified as Level 3 in the cash outflows relating to those obligations based onfair value hierarchy for the current call price,periods ended June 30, 2012 and December 31, 2011:
|
| | | | | | | | | | | | |
| | | Derivative Asset FTRs | | Derivative Liability FTRs | | Net FTRs |
| | | (In millions) | | | | |
| January 1, 2011 Balance | | $ | — |
| | $ | — |
| | $ | — |
|
| Realized gain (loss) | | — |
| | — |
| | — |
|
| Unrealized gain (loss) | | 4 |
| | (8 | ) | | (4 | ) |
| Purchases | | 2 |
| | (1 | ) | | 1 |
|
| Issuances | | — |
| | — |
| | — |
|
| Sales | | — |
| | — |
| | — |
|
| Settlements | | (5 | ) | | 2 |
| | (3 | ) |
| Transfers in (out) of Level 3 | | — |
| | — |
| | — |
|
| December 31, 2011 Balance | | $ | 1 |
| | $ | (7 | ) | | $ | (6 | ) |
| Realized gain (loss) | | — |
| | — |
| | — |
|
| Unrealized gain (loss) | | — |
| | (1 | ) | | (1 | ) |
| Purchases | | 8 |
| | (7 | ) | | 1 |
|
| Issues | | — |
| | — |
| | — |
|
| Sales | | — |
| | — |
| | — |
|
| Settlements | | (1 | ) | | 9 |
| | 8 |
|
| Transfers in (out) of Level 3 | | — |
| | — |
| | — |
|
| June 30, 2012 Balance | | $ | 8 |
| | $ | (6 | ) | | $ | 2 |
|
Level 3 Quantitative Information
The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the yield to maturity orfair value hierarchy for the yield to call,period ended June 30, 2012:
|
| | | | | | | | | | | | | | |
| | | Fair Value as of June 30, 2012 (In millions) | | Valuation Technique | | Significant Input | | Range | | Weighted Average | | Units |
| FTRs | | $ | 2 |
| | Model | | RTO auction clearing prices | | ($3.60) to $4.90 | | $0.50 | | Dollars/MWH |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| OE | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements | June 30, 2012 | | December 31, 2011 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | (In millions) |
| Corporate debt securities | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
| | $ | — |
| | $ | 3 |
|
| U.S. government debt securities | — |
| | 138 |
| | — |
| | 138 |
| | — |
| | 132 |
| | — |
| | 132 |
|
Other(1) | — |
| | 3 |
| | — |
| | 3 |
| | — |
| | 2 |
| | — |
| | 2 |
|
Total assets(2) | $ | — |
| | $ | 141 |
| | $ | — |
| | $ | 141 |
| | $ | — |
| | $ | 137 |
| | $ | — |
| | $ | 137 |
|
| |
(1) | Primarily consists of short-term cash investments. |
| |
(2) | Excludes $1 million as of June 30, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table. |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| JCP&L | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Recurring Fair Value Measurements | June 30, 2012 | | December 31, 2011 |
| | Level 1 | | Level 2 | | Level 3 | | Total | | Level 1 | | Level 2 | | Level 3 | | Total |
| Assets | (In millions) |
| Corporate debt securities | $ | — |
| | $ | 149 |
| | $ | — |
| | $ | 149 |
| | $ | — |
| | $ | 144 |
| | $ | — |
| | $ | 144 |
|
Derivative assets - NUG contracts(1) | — |
| | — |
| | 4 |
| | 4 |
| | — |
| | — |
| | 4 |
| | 4 |
|
Equity securities(2) | 30 |
| | — |
| | — |
| | 30 |
| | 30 |
| | — |
| | — |
| | 30 |
|
| U.S. government debt securities | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | — |
| | 2 |
|
| U.S. state debt securities | — |
| | 223 |
| | — |
| | 223 |
| | — |
| | 219 |
| | — |
| | 219 |
|
Other(3) | — |
| | 19 |
| | — |
| | 19 |
| | — |
| | 15 |
| | — |
| | 15 |
|
| Total assets | 30 |
| | 391 |
| | 4 |
| | 425 |
| | 30 |
| | 380 |
| | 4 |
| | 414 |
|
| | | | | | | | | | | | | | | | |
| Liabilities | | | | | | | | | | | | | | | |
Derivative liabilities - NUG contracts(1) | — |
| | — |
| | (125 | ) | | (125 | ) | | — |
| | — |
| | (147 | ) | | (147 | ) |
Derivative liabilities - LCAPP contracts(1) | — |
| | — |
| | (145 | ) | | (145 | ) | | — |
| | — |
| | — |
| | — |
|
| Total liabilities | — |
| | — |
| | (270 | ) | | (270 | ) | | — |
| | — |
| | (147 | ) | | (147 | ) |
| | | | | | | | | | | | | | | | |
Net assets (liabilities)(4) | $ | 30 |
| | $ | 391 |
| | $ | (266 | ) | | $ | 155 |
| | $ | 30 |
| | $ | 380 |
| | $ | (143 | ) | | $ | 267 |
|
| |
(1) | NUG and LCAPP contracts are subject to regulatory accounting treatment and do not impact earnings. |
| |
(2) | NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index. |
| |
(3) | Primarily consists of short-term cash investments. |
| |
(4) | Excludes $2 million as of June 30, 2012 and December 31, 2011 of receivables, payables, 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 and LCAPP contracts held by JCP&L and classified as deemed appropriate atLevel 3 in the end of each respective period. fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | NUG Contracts(1) | | LCAPP Contracts(1) |
| | Derivative Assets | | Derivative Liabilities | | Net | | Derivative Assets | | Derivative Liabilities | | Net |
| | | | | | | | | | | | |
| January 1, 2011 Balance | $ | 6 |
| | $ | (233 | ) | | $ | (227 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Realized gain (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrealized gain (loss) | (2 | ) | | (11 | ) | | (13 | ) | | — |
| | — |
| | — |
|
| Purchases | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Issuances | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Sales | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements | — |
| | 97 |
| | 97 |
| | — |
| | — |
| | — |
|
| Transfers in (out) of Level 3 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| December 31, 2011 Balance | $ | 4 |
| | $ | (147 | ) | | $ | (143 | ) | | $ | — |
| | $ | — |
| | $ | — |
|
| Realized gain (loss) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Unrealized gain (loss) | — |
| | (7 | ) | | (7 | ) | | — |
| | — |
| | — |
|
| Purchases | — |
| | — |
| | — |
| | — |
| | (145 | ) | | (145 | ) |
| Issues | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Sales | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Settlements | — |
| | 29 |
| | 29 |
| | — |
| | — |
| | — |
|
| Transfers in (out) of Level 3 | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| June 30, 2012 Balance | $ | 4 |
| | $ | (125 | ) | | $ | (121 | ) | | $ | — |
| | $ | (145 | ) | | $ | (145 | ) |
| |
(1) | Changes in the fair value of NUG and LCAPP contracts are subject to regulatory accounting treatment and do not impact earnings. |
Level 3 Quantitative Information
The yields assumed were based on debt with similar characteristics offeredfollowing table provides quantitative information for NUG and LCAPP contracts held by corporations with credit ratings similar to those of FirstEnergy, FES,JCP&L that are classified as Level 3 in the Utilities and other subsidiaries.fair value hierarchy for the period ended June 30, 2012:
|
| | | | | | | | | | | | | | |
| | | Fair Value as of June 30, 2012 (In millions) | | Valuation Technique | | Significant Input | | Range | | Weighted Average | | Units |
| NUG Contracts | | $ | (121 | ) | | Model | | Generation Electricity regional prices | | 63,000 to 715,000 $49.50 to $84.90 | | 166,000 $65.80 | | MWH Dollars/MWH |
| LCAPP Contracts | | $ | (145 | ) | | Model | | Regional capacity prices | | $94.90 to $248.40 | | $183.90 | | Dollars/MW-Day |
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 and available-for-sale securitiessecurities.
FE and notes receivable.
FES and the Utilitiesits subsidiaries 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’ssecurity'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, FESFE and the Utilitiesits subsidiaries 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’ssecurity's entire amortized cost basis.
31
Unrealized gains applicable to the decommissioning trusts of FES OE and TEOE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to 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 the trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the nuclear decommissioning trustNDT funds restricts or limits the trusts’trusts' 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 funds’funds' custodian or managers and their parents or subsidiaries.
Available-For-Sale Securities
FES, OE and the UtilitiesJCP&L hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale securities at fair market value. FES, OE and the UtilitiesJCP&L 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 NDT, nuclear fuel disposal trusts and NUG trusts as of June 30, 20112012 and December 31, 2010:2011:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 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 | | $ | 2,015 | | | $ | 48 | | | $ | — | | | $ | 2,063 | | | $ | 1,699 | | | $ | 31 | | | $ | — | | | $ | 1,730 | |
| FES | | | 1,023 | | | | 26 | | | | — | | | | 1,049 | | | | 980 | | | | 13 | | | | — | | | | 993 | |
| OE | | | 128 | | | | 3 | | | | — | | | | 131 | | | | 123 | | | | 1 | | | | — | | | | 124 | |
| TE | | | 52 | | | | 1 | | | | — | | | | 53 | | | | 42 | | | | — | | | | — | | | | 42 | |
| JCP&L | | | 353 | | | | 9 | | | | — | | | | 362 | | | | 281 | | | | 9 | | | | — | | | | 290 | |
| Met-Ed | | | 249 | | | | 5 | | | | — | | | | 254 | | | | 127 | | | | 4 | | | | — | | | | 131 | |
| Penelec | | | 210 | | | | 4 | | | | — | | | | 214 | | | | 145 | | | | 4 | | | | — | | | | 149 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Equity securities | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 187 | | | $ | 11 | | | $ | — | | | $ | 198 | | | $ | 268 | | | $ | 69 | | | $ | — | | | $ | 337 | |
| FES | | | 90 | | | | 6 | | | | — | | | | 96 | | | | — | | | | — | | | | — | | | | — | |
| TE | | | 24 | | | | 2 | | | | — | | | | 26 | | | | — | | | | — | | | | — | | | | — | |
| JCP&L | | | 21 | | | | 1 | | | | — | | | | 22 | | | | 80 | | | | 17 | | | | — | | | | 97 | |
| Met-Ed | | | 32 | | | | 1 | | | | — | | | | 33 | | | | 125 | | | | 35 | | | | — | | | | 160 | |
| Penelec | | | 20 | | | | 1 | | | | — | | | | 21 | | | | 63 | | | | 16 | | | | — | | | | 79 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2012(1) | | December 31, 2011(2) |
| | | Cost Basis | | Unrealized Gains | | Unrealized Losses | | Fair Value | | Cost Basis | | Unrealized Gains | | Unrealized Losses | | Fair Value |
| | | (In millions) |
| Debt securities | | | | | | | | | | | | | | |
| FE Consolidated | | $ | 2,032 |
| | $ | 52 |
| | $ | — | | | $ | 2,084 |
| | $ | 1,980 |
| | $ | 25 |
| 25 |
| $ | — |
| — |
| $ | 2,005 |
|
| FES | | 1,034 |
| | 29 |
| | — | | | 1,063 |
| | 1,012 |
| | 13 |
| | — |
| | 1,025 |
|
| OE | | 138 |
| | — |
| | — | | | 138 |
| | 134 |
| | — |
| | — |
| | 134 |
|
| JCP&L | | 358 |
| | 12 |
| | — | | | 370 |
| | 356 |
| | 7 |
| | — |
| | 363 |
|
| | | | | | | | | | | | | | | | | |
| Equity securities | | | | | | | | | | | | | | |
| FE Consolidated | | $ | 243 |
| | $ | 36 |
| | $ | — | | | $ | 279 |
| | $ | 222 |
| | $ | 36 |
| | $ | — |
| | $ | 258 |
|
| FES | | 125 |
| | 19 |
| | — | | | 144 |
| | 104 |
| | 20 |
| | — |
| | 124 |
|
| JCP&L | | 27 |
| | 3 |
| | — | | | 30 |
| | 27 |
| | 3 |
| | — |
| | 30 |
|
| | |
(1) | | Excludes short-term cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $130 million;investments: FE Consolidated - $113 million; FES – $39 million;- $42 million; OE – $3 million;- $3 million; JCP&L – $19 million; Met-Ed – $14- $23 million and Penelec – $55 million.. |
| |
|
(2) | | Excludes short-term cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $193 million;investments: FE Consolidated - $164 million; FES – $153 million;- $74 million; OE – $3 million; TE – $34 million;- $2 million; JCP&L – $3 million; Met-Ed – $(3)- $19 million and Penelec – $4 million.. |
32
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the three months and six months ended June 30, 20112012 and 20102011 were as follows:
| | | | | | | | | | | | | | | | | |
| Three Months Ended June 30, | |
| |
| | | | | | | | | | | | | | | Interest and | |
| 2011 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 734 | | | $ | 22 | | | $ | (16 | ) | | $ | 28 | |
| FES | | | 297 | | | | 10 | | | | (7 | ) | | | 17 | |
| OE | | | 12 | | | | — | | | | — | | | | 1 | |
| TE | | | 15 | | | | 1 | | | | (1 | ) | | | 1 | |
| JCP&L | | | 159 | | | | 4 | | | | (2 | ) | | | 4 | |
| Met-Ed | | | 165 | | | | 4 | | | | (3 | ) | | | 3 | |
| Penelec | | | 86 | | | | 3 | | | | (3 | ) | | | 2 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Interest and | |
| 2010 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 1,183 | | | $ | 46 | | | $ | (36 | ) | | $ | 16 | |
| FES | | | 685 | | | | 41 | | | | (35 | ) | | | 9 | |
| OE | | | 57 | | | | 2 | | | | — | | | | — | |
| TE | | | 76 | | | | 2 | | | | — | | | | — | |
| JCP&L | | | 91 | | | | — | | | | — | | | | 3 | |
| Met-Ed | | | 233 | | | | 1 | | | | (1 | ) | | | 2 | |
| Penelec | | | 41 | | | | — | | | | — | | | | 2 | |
|
| | | | | | | | | | | | | | | | |
| Three Months Ended |
| | | | | | | | | |
| June 30, 2012 | | Sales Proceeds | | Realized Gains | | Realized Losses | | Interest and Dividend Income |
| | | (In millions) |
| FE Consolidated | | $ | 131 |
| | $ | 17 |
| | $ | (18 | ) | | $ | 18 |
|
| FES | | 25 |
| | 13 |
| | (14 | ) | | 11 |
|
| OE | | 20 |
| | — |
| | — |
| | 1 |
|
| JCP&L | | 70 |
| | 1 |
| | (1 | ) | | 3 |
|
| June 30, 2011 | | Sales Proceeds | | Realized Gains | | Realized Losses | | Interest and Dividend Income |
| | | (In millions) |
| FE Consolidated | | $ | 734 |
| | $ | 22 |
| | $ | (16 | ) | | $ | 28 |
|
| FES | | 297 |
| | 10 |
| | (7 | ) | | 17 |
|
| OE | | 12 |
| | — |
| | — |
| | 1 |
|
| JCP&L | | 159 |
| | 4 |
| | (2 | ) | | 4 |
|
| | | | | | | | | | | | | | | | | |
| Six Months Ended June 30, | |
| |
| | | | | | | | | | | | | | | Interest and | |
| 2011 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 1,703 | | | $ | 122 | | | $ | (45 | ) | | $ | 52 | |
| FES | | | 513 | | | | 22 | | | | (23 | ) | | | 32 | |
| OE | | | 20 | | | | — | | | | — | | | | 2 | |
| TE | | | 28 | | | | 1 | | | | (2 | ) | | | 1 | |
| JCP&L | | | 376 | | | | 26 | | | | (6 | ) | | | 8 | |
| Met-Ed | | | 501 | | | | 48 | | | | (7 | ) | | | 5 | |
| Penelec | | | 265 | | | | 25 | | | | (7 | ) | | | 4 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Interest and | |
| 2010 | | Sales Proceeds | | | Realized Gains | | | Realized Losses | | | Dividend Income | |
| | | (In millions) | |
| FirstEnergy | | $ | 1,915 | | | $ | 83 | | | $ | (86 | ) | | $ | 37 | |
| FES | | | 957 | | | | 54 | | | | (58 | ) | | | 22 | |
| OE | | | 60 | | | | 2 | | | | — | | | | 1 | |
| TE | | | 107 | | | | 3 | | | | — | | | | 1 | |
| JCP&L | | | 281 | | | | 9 | | | | (9 | ) | | | 7 | |
| Met-Ed | | | 377 | | | | 9 | | | | (12 | ) | | | 3 | |
| Penelec | | | 134 | | | | 6 | | | | (7 | ) | | | 3 | |
|
| | | | | | | | | | | | | | | | |
| Six Months Ended |
| | | | | | | | | |
| June 30, 2012 | | Sales Proceeds | | Realized Gains | | Realized Losses | | Interest and Dividend Income |
| | | (In millions) |
| FE Consolidated | | $ | 382 |
| | $ | 37 |
| | $ | (35 | ) | | $ | 33 |
|
| FES | | 109 |
| | 26 |
| | (25 | ) | | 18 |
|
| OE | | 57 |
| | — |
| | — |
| | 1 |
|
| JCP&L | | 165 |
| | 2 |
| | (2 | ) | | 7 |
|
| June 30, 2011 | | Sales Proceeds | | Realized Gains | | Realized Losses | | Interest and Dividend Income |
| | | (In millions) |
| FE Consolidated | | $ | 1,703 |
| | $ | 122 |
| | $ | (45 | ) | | $ | 52 |
|
| FES | | 513 |
| | 22 |
| | (23 | ) | | 32 |
|
| OE | | 20 |
| | — |
| | — |
| | 2 |
|
| JCP&L | | 376 |
| | 26 |
| | (6 | ) | | 8 |
|
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 June 30, 20112012 and December 31, 2010:2011:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 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 | | $ | 414 | | | $ | 84 | | | $ | — | | | | 498 | | | $ | 476 | | | $ | 91 | | | $ | — | | | $ | 567 | |
| OE | | | 178 | | | | 45 | | | | — | | | | 223 | | | | 190 | | | | 51 | | | | — | | | | 241 | |
| CEI | | | 287 | | | | 39 | | | | — | | | | 326 | | | | 340 | | | | 41 | | | | — | | | | 381 | |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | June 30, 2012 | | December 31, 2011 |
| | | Cost Basis | | Unrealized Gains | | Fair Value | | Cost Basis | | Unrealized Gains | | Fair Value |
| | | (In millions) |
| Debt Securities | | | | | | | | | | | | |
| FE Consolidated | | $ | 326 |
| | $ | 55 |
| | $ | 381 |
| | $ | 402 |
| | $ | 50 |
| | $ | 452 |
|
| OE | | 148 |
| | 32 |
| | 180 |
| | 163 |
| | 21 |
| | 184 |
|
Investments in emission allowances, employee benefitsbenefit trusts and cost and equity method investments totaling $345$716 million as of June 30, 20112012, and $259$693 million as of December 31, 2010, are not required to be disclosed and2011, are excluded from the amounts reported above.
33
Notes Receivable
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 in "Short-term borrowings" on the Consolidated Balance Sheets at cost, which approximates their fair market value. The following table below provides the approximate fair value and related carrying amounts of notes receivablelong-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts, as of June 30, 20112012 and December 31, 2010. 2011:
|
| | | | | | | | | | | | | | | |
| | June 30, 2012 | | December 31, 2011 |
| | Carrying Value | | Fair Value | | Carrying Value | | Fair Value |
| | (In millions) |
| FE Consolidated | $ | 16,571 |
| | $ | 18,998 |
| | $ | 17,165 |
| | $ | 19,320 |
|
| FES | 3,617 |
| | 3,862 |
| | 3,675 |
| | 3,931 |
|
| OE | 1,157 |
| | 1,493 |
| | 1,157 |
| | 1,434 |
|
| JCP&L | 1,762 |
| | 2,076 |
| | 1,777 |
| | 2,080 |
|
The fair valuevalues of notes receivable representslong-term debt and other long-term obligations reflect the present value of the cash inflowsoutflows relating to those securities based on the current call price, the yield to maturity.maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on financial instrumentssecurities with similar characteristics and terms. The maturity dates range from 2013offered by corporations with credit ratings similar to 2021.
| | | | | | | | | | | | | | | | | |
| | | June 30, 2011 | | | December 31, 2010 | |
| | | Carrying | | | Fair | | | Carrying | | | Fair | |
| | | Value | | | Value | | | Value | | | Value | |
| | | (In millions) | |
Notes Receivable | | | | | | | | | | | | | | | | |
| FirstEnergy | | $ | 6 | | | $ | 7 | | | $ | 7 | | | $ | 8 | |
| TE | | | 82 | | | | 94 | | | | 104 | | | | 118 | |
34
(C) RECURRING FAIR VALUE MEASUREMENTS
Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.
The three levelsthose of the fair value hierarchy are as follows:
| | |
|
Level 1 | | — Quoted prices for identical instruments in active markets. |
| | |
Level 2 | | — Quoted prices for similar instruments in active markets; |
| | |
| | — quoted prices for identical or similar instruments in markets that are not active; and |
| | |
| | — model-derived valuations for which all significant inputs are observable market data. |
| | |
Level 3 | | — Valuation inputs are unobservable and significant to the fair value measurement. |
The following tables set forth financial assets and liabilities measured at fair value on a recurring basis by level within the fair value hierarchy. There were no significant transfers between levels during the three months and six months ended June 30, 2011.
35
FirstEnergy Corp.
The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
Corporate debt securities | | $ | — | | | $ | 868 | | | $ | — | | | $ | 868 | |
Derivative assets — commodity contracts | | | — | | | | 312 | | | | — | | | | 312 | |
Derivative assets — FTRs | | | — | | | | — | | | | 13 | | | | 13 | |
Derivative assets — interest rate swaps | | | — | | | | 4 | | | | — | | | | 4 | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 75 | | | | 75 | |
Equity securities(2) | | | 198 | | | | — | | | | — | | | | 198 | |
Foreign government debt securities | | | — | | | | 206 | | | | — | | | | 206 | |
U.S. government debt securities | | | — | | | | 673 | | | | — | | | | 673 | |
U.S. state debt securities | | | — | | | | 306 | | | | — | | | | 306 | |
Other(4) | | | — | | | | 146 | | | | — | | | | 146 | |
| | | | | | | | | | | | | |
Total assets | | $ | 198 | | | $ | 2,515 | | | $ | 88 | | | $ | 2,801 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities — commodity contracts | | $ | — | | | $ | (362 | ) | | $ | — | | | $ | (362 | ) |
Derivative liabilities — FTRs | | | — | | | | — | | | | (7 | ) | | | (7 | ) |
Derivative liabilities — interest rate swaps | | | — | | | | (5 | ) | | | — | | | | (5 | ) |
Derivative liabilities — NUG contracts(1) | | | — | | | | — | | | | (522 | ) | | | (522 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | (367 | ) | | $ | (529 | ) | | $ | (896 | ) |
| | | | | | | | | | | | | |
| |
Net assets (liabilities)(3) | | $ | 198 | | | $ | 2,148 | | | $ | (441 | ) | | $ | 1,905 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 generally subject to regulatory accounting and do not materially 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 $6 million and $(7) million as of June 30, 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. |
36
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 its subsidiaries listed above. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 32 in the fair value hierarchy during the periods ending as of June 30, 20112012 and December 31, 2010:2011.
| | | | | | | | | | | | | |
| | | Derivative Asset(1) | | | Derivative Liability(1) | | | Net(1) | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | 122 | | | $ | (466 | ) | | $ | (344 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | (40 | ) | | | (203 | ) | | | (243 | ) |
| Purchases | | | 13 | | | | (3 | ) | | | 10 | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (6 | ) | | | 154 | | | | 148 | |
| Transfers into Level 3 | | | — | | | | (12 | ) | | | (12 | ) |
| | | | | | | | | | |
| June 30, 2011 Balance | | $ | 89 | | | $ | (530 | ) | | $ | (441 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| January 1, 2010 Balance | | $ | 200 | | | $ | (643 | ) | | $ | (443 | ) |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | (71 | ) | | | (110 | ) | | | (181 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (7 | ) | | | 287 | | | | 280 | |
| Transfers into Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| December 31, 2010 Balance | | $ | 122 | | | $ | (466 | ) | | $ | (344 | ) |
| | | | | | | | | | |
| | |
(1) | | Changes in the fair value of NUG contracts are generally subject to regulatory accounting and do not materially impact earnings. |
37
FirstEnergy Solutions Corp.
The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:27
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 562 | | | $ | — | | | $ | 562 | |
| Derivative assets — commodity contracts | | | — | | | | 283 | | | | — | | | | 283 | |
| Derivative assets — FTRs | | | — | | | | — | | | | 2 | | | | 2 | |
Equity securities(3) | | | 96 | | | | — | | | | — | | | | 96 | |
| Foreign government debt securities | | | — | | | | 160 | | | | — | | | | 160 | |
| U.S. government debt securities | | | — | | | | 316 | | | | — | | | | 316 | |
| U.S. state debt securities | | | — | | | | 7 | | | | — | | | | 7 | |
Other(2) | | | — | | | | 42 | | | | — | | | | 42 | |
| | | | | | | | | | | | | |
Total assets | | $ | 96 | | | $ | 1,370 | | | $ | 2 | | | $ | 1,468 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
| Derivative liabilities — commodity contracts | | $ | — | | | $ | (327 | ) | | $ | — | | | $ | (327 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | (327 | ) | | $ | — | | | $ | (327 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(1) | | $ | 96 | | | $ | 1,043 | | | $ | 2 | | | $ | 1,141 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 $7 million as of 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. |
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 during the period ending June 30, 2011:
| | | | | | | | | | | | | |
| | | Derivative Asset | | | Derivative Liability | | | Net | |
| | | FTRs | | | FTRs | | | FTRs | |
| | | (In millions) | |
| January 1, 2011 Balance | | $ | — | | | $ | — | | | $ | — | |
| Realized gain (loss) | | | — | | | | — | | | | — | |
| Unrealized gain (loss) | | | 1 | | | | — | | | | 1 | |
| Purchases | | | 2 | | | | — | | | | 2 | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (1 | ) | | | — | | | | (1 | ) |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| June 30, 2011 Balance | | $ | 2 | | | $ | — | | | $ | 2 | |
| | | | | | | | | | |
38
The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| U.S. government debt securities | | $ | — | | | $ | 131 | | | $ | — | | | $ | 131 | |
| Other | | | — | | | | 2 | | | | — | | | | 2 | |
| | | | | | | | | | | | | |
Total assets(1) | | $ | — | | | $ | 133 | | | $ | — | | | $ | 133 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 $2 million and $1 million as of June 30, 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. |
The Toledo Edison Company
The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 16 | | | $ | — | | | $ | 16 | |
Equity securities(3) | | | 26 | | | | — | | | | — | | | | 26 | |
| U.S. government debt securities | | | — | | | | 33 | | | | — | | | | 33 | |
| U.S. state debt securities | | | — | | | | 1 | | | | — | | | | 1 | |
Other(2) | | | — | | | | 3 | | | | — | | | | 3 | |
| | | | | | | | | | | | | |
Total assets(1) | | $ | 26 | | | $ | 53 | | | $ | — | | | $ | 79 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 June 30, 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. |
39
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 June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 81 | | | $ | — | | | $ | 81 | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 5 | | | | 5 | |
Equity securities(2) | | | 21 | | | | — | | | | — | | | | 21 | |
| Foreign government debt securities | | | — | | | | 13 | | | | — | | | | 13 | |
| U.S. government debt securities | | | — | | | | 54 | | | | — | | | | 54 | |
| U.S. state debt securities | | | — | | | | 215 | | | | — | | | | 215 | |
| Other | | | — | | | | 14 | | | | — | | | | 14 | |
| | | | | | | | | | | | | |
Total assets | | $ | 21 | | | $ | 377 | | | $ | 5 | | | $ | 403 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities — NUG contracts(1) | | $ | — | | | $ | — | | | $ | (240 | ) | | $ | (240 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (240 | ) | | $ | (240 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 21 | | | $ | 377 | | | $ | (235 | ) | | $ | 163 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 $5 million and $(3) million as of June 30, 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. |
40
Rollforward of Level 3 Measurements
The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 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) | | | (1 | ) | | | (71 | ) | | | (72 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | 64 | | | | 64 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| June 30, 2011 Balance | | $ | 5 | | | $ | (240 | ) | | $ | (235 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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 | ) |
| | | | | | | | | | |
| | |
(1) | | Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings. |
41
Metropolitan Edison Company
The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 138 | | | $ | — | | | $ | 138 | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 66 | | | | 66 | |
Equity securities(2) | | | 33 | | | | — | | | | — | | | | 33 | |
| Foreign government debt securities | | | — | | | | 20 | | | | — | | | | 20 | |
| U.S. government debt securities | | | — | | | | 87 | | | | — | | | | 87 | |
| U.S. state debt securities | | | — | | | | 2 | | | | — | | | | 2 | |
| Other | | | — | | | | 22 | | | | — | | | | 22 | |
| | | | | | | | | | | | | |
Total assets | | $ | 33 | | | $ | 269 | | | $ | 66 | | | $ | 368 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities — NUG contracts(1) | | $ | — | | | $ | — | | | $ | (122 | ) | | $ | (122 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (122 | ) | | $ | (122 | ) |
| | | | | | | | | | | | | |
| |
Net assets (liabilities)(3) | | $ | 33 | | | $ | 269 | | | $ | (56 | ) | | $ | 246 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 June 30, 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. |
42
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 during the periods ending June 30, 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) | | | (42 | ) | | | (36 | ) | | | (78 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | (4 | ) | | | 30 | | | | 26 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| June 30, 2011 Balance | | $ | 66 | | | $ | (122 | ) | | $ | (56 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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. |
43
Pennsylvania Electric Company
The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:
| | | | | | | | | | | | | | | | | |
| June 30, 2011 | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | (In millions) | |
Assets | | | | | | | | | | | | | | | | |
| Corporate debt securities | | $ | — | | | $ | 69 | | | $ | — | | | $ | 69 | |
Derivative assets — NUG contracts(1) | | | — | | | | — | | | | 4 | | | | 4 | |
Equity securities(2) | | | 20 | | | | — | | | | — | | | | 20 | |
| Foreign government debt securities | | | | | | | 12 | | | | | | | | 12 | |
| U.S. government debt securities | | | — | | | | 52 | | | | — | | | | 52 | |
| U.S. state debt securities | | | — | | | | 81 | | | | — | | | | 81 | |
| Other | | | — | | | | 53 | | | | — | | | | 53 | |
| | | | | | | | | | | | | |
Total assets | | $ | 20 | | | $ | 267 | | | $ | 4 | | | $ | 291 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Liabilities | | | | | | | | | | | | | | | | |
Derivative liabilities — NUG contracts(1) | | $ | — | | | $ | — | | | $ | (160 | ) | | $ | (160 | ) |
| | | | | | | | | | | | | |
Total liabilities | | $ | — | | | $ | — | | | $ | (160 | ) | | $ | (160 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Net assets (liabilities)(3) | | $ | 20 | | | $ | 267 | | | $ | (156 | ) | | $ | 131 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| 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 $1 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table. |
44
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 during the periods ended June 30, 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) | | | — | | | | (88 | ) | | | (88 | ) |
| Purchases | | | — | | | | — | | | | — | |
| Issuances | | | — | | | | — | | | | — | |
| Sales | | | — | | | | — | | | | — | |
| Settlements | | | — | | | | 45 | | | | 45 | |
| Transfers in (out) of Level 3 | | | — | | | | — | | | | — | |
| | | | | | | | | | |
| June 30, 2011 Balance | | $ | 4 | | | $ | (160 | ) | | $ | (156 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| 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. |
5.7. 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’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy 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 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 purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualifyqualified and arewere designated as cash flow hedge instruments are recorded in AOCL.AOCI. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has these contractual derivative agreements through December 2018.2018.
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 thea derivative contract are reported as a component of AOCLAOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.
As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were $104 million of assets and $101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCLAOCI associated with dedesignatedde-designated cash flow hedges totaled $8$15 million and $19 million as of June 30, 2011.2012 and December 31, 2011, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCLAOCI into other operating expenses totaled $14were $1 million and $19$14 million during the three months ended June 30, 2012and 2011, respectively, and $4 million and $19 million during the six months ended June 30, 2012 and 2011, respectively. Approximately $3$9 million is expected to be amortized to expenseincome during the next twelve months.
FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of June 30, 2011, 2012, no forward starting swap agreements accounted for as a cash flow hedge were outstanding. Total unamortized losses included in AOCLAOCI associated with prior interest rate cash flow hedges totaled $84$74 million ($55 million net of tax) as of June 30, 2011.2012. Based on current estimates, approximately $10$9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCLAOCI into interest expense totaled $3$2 million and $3 million during the three months ended June 30, 20112012 and 20102011, respectively, and $6$5 million and $6 million during the six months ended June 30, 20112012 and 2010.2011, respectively.
45
Fair Value Hedges
FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of June 30, 2011, 2012, no fixed-for-floating interest rate swap agreements were outstanding.
Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $113$91 million ($73 million net of tax) as of June 30, 2011.2012. Based on current estimates, approximately $22$23 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $6$6 million and $2 million during the three months ended June 30, 20112012 and 2010, respectively2011, and $11$11 million and $3 million during the six months ended June 30, 20112012 and 2010, respectively.2011.
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.
Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas;gas primarily natural gas is usedfor use 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 June 30, 2011,2012, FirstEnergy’s net liabilityasset position under commodity derivative contracts was $45$78 million, which primarily related to FES and AE Supply positions. Under these commodity derivative contracts, FES posted $81$34 million and Allegheny posted $2 million in of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $49$12 million of additional collateral
if the credit rating for its debt were to fall below investment grade.
Based on commodity derivative contracts held as of June 30, 2011,2012, an adverse 10% change in commodity prices would decrease net income by approximately $31$2 million ($20 million net of tax) during the next twelve months.
FTRsInterest Rate Swaps
FirstEnergy uses 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 are considered economic hedges, protecting against the risk of increases in future interest payments resulting from increases in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the three months ended June 30, 2012, FirstEnergy executed forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties for a combined notional value of $1.6 billion in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%. Changes in the fair value of the forward starting swap agreements are recorded in net income on a mark-to-market basis.
LCAPP
The LCAPP law was enacted in New Jersey during 2011 to promote the construction of qualified electric generation facilities. JCP&L maintains two LCAPP contracts, which are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. During the second quarter of 2012, JCP&L began to account for these contracts as derivatives as a result of the generators clearing the 2015/2016 PJM RPM capacity auction. JCP&L expects to recover from its customers payments made to the generators and give credit to customers for payments from the generators under these contracts. As a result, the projected future obligations for the LCAPP contracts are reflected on the Consolidated Balance Sheets as derivative liabilities (assets) with a corresponding regulatory asset (liability). Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings.
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. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.
The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the 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. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.
46
The following tables summarize the fair value of derivative instruments inon FirstEnergy’s Consolidated Balance Sheets:
Derivatives not designated as hedging instruments as of June 30, 2011:| | | | | | | | | | |
| Derivative Assets | | |
| | |
| | | Fair Value | | | | | | | | | | | | | |
| | | June 30, | | December 31, | | |
| Derivatives not designated as hedging instruments: | | Derivatives not designated as hedging instruments: |
| Derivative Assets | | Derivative Assets | | Derivative Liabilities |
| | | 2011 | | 2010 | | Fair Value | | | Fair Value |
| | | (In millions) | | June 30,
2012 | | December 31,
2011 | | | June 30,
2012 | | December 31,
2011 |
| | | (In millions) | | | (In millions) |
| Power Contracts | | | | | | Power Contracts | | | |
| Current Assets | | $ | 210 | | $ | 96 | | $ | 232 |
| | $ | 185 |
| | Current Liabilities | $ | (213 | ) | | $ | (196 | ) |
| Noncurrent Assets | | 102 | | 40 | | 106 |
| | 79 |
| | Noncurrent Liabilities | (49 | ) | | (51 | ) |
| FTRs | | | | | | FTRs | | | |
| Current Assets | | 13 | | — | | 12 |
| | 1 |
| | Current Liabilities | (8 | ) | | (22 | ) |
| Noncurrent Assets | | — | | — | | — |
| | — |
| | Noncurrent Liabilities | (1 | ) | | (1 | ) |
| NUGs | | 9 |
| | 56 |
| | NUGs | (302 | ) | | (349 | ) |
| Current Assets | | 4 | | 3 | | |
| Noncurrent Assets | | 71 | | 119 | | |
| LCAPP | | — |
| | — |
| | LCAPP | (145 | ) | | — |
|
| Interest Rate Swaps | | | | | | Interest Rate Swaps | | | |
| Current Assets | | 4 | | — | | |
| Noncurrent Assets | | — | | — | | 3 |
| | — |
| | Noncurrent Liabilities | (23 | ) | | — |
|
| Other | | | | | | Other | | | |
| Current Assets | | — | | 10 | | 4 |
| | — |
| | Current Liabilities | (1 | ) | | — |
|
| Noncurrent Assets | | — | | — | | |
| | | | | | | $ | 366 |
| | $ | 321 |
| | $ | (742 | ) | | $ | (619 | ) |
| Total Derivatives | | $ | 404 | | $ | 268 | | |
| | | | | | | |
| | | | | | | | | |
| Derivative Liabilities | |
| |
| | | Fair Value | |
| | | June 30, | | | December 31, | |
| | | 2011 | | | 2010 | |
| | | (In millions) | |
| | | | | | | | | |
| Power Contracts | | | | | | | | |
| Current Liabilities | | $ | 274 | | | $ | 209 | |
| Noncurrent Liabilities | | | 88 | | | | 38 | |
| FTRs | | | | | | | | |
| Current Liabilities | | | 7 | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| NUGs | | | | | | | | |
| Current Liabilities | | | 317 | | | | 229 | |
| Noncurrent Liabilities | | | 205 | | | | 238 | |
| Interest Rate Swaps | | | | | | | | |
| Current Liabilities | | | 5 | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| Other | | | | | | | | |
| Current Liabilities | | | — | | | | — | |
| Noncurrent Liabilities | | | — | | | | — | |
| | | | | | | |
| Total Derivatives | | $ | 896 | | | $ | 714 | |
| | | | | | | |
The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2011:2012:
| | | | | | | | | | | | | | | |
| | | Purchases | | | Sales | | | Net | | | Units |
| | | (In thousands) |
| Power Contracts | | | 45,573 | | | | (59,549 | ) | | | (13,976 | ) | | MWH |
| FTRs | | | 53,656 | | | | — | | | | 53,656 | | | MWH |
| Interest Rate Swaps | | | 200,000 | | | | (200,000 | ) | | | — | | | notional dollars |
| NUGs | | | 26,903 | | | | — | | | | 26,903 | | | MWH |
47
|
| | | | | | | | | | |
| | Purchases | | Sales | | Net | | Units |
| | (In millions) |
| Power Contracts | 29 |
| | 40 |
| | (11 | ) | | MWH |
| FTRs | 82 |
| | — |
| | 82 |
| | MWH |
| Interest Rate Swaps | 1,600 |
| | — |
| | 1,600 |
| | notional dollars |
| NUGs | 22 |
| | — |
| | 22 |
| | MWH |
| LCAPP | 408 |
| | — |
| | 408 |
| | MW |
| Natural Gas | 26 |
| | — |
| | 26 |
| | Million BTUs |
The effect of derivative instruments on the Consolidated Statements of Income during the three months and six months ended June 30, 20112012 and 2010,2011, are summarized in the following tables:
| | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended June 30, | |
| | | Power | | | | | | | Interest | | | | | | | |
| | | Contracts | | | FTRs | | | Rate Swaps | | | Other | | | Total | |
| | | (In millions) | |
Derivatives in a Hedging Relationship | | | | | | | | | | | | | | | | | | | | |
2011 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | 14 | | | $ | — | | | $ | — | | | $ | — | | | $ | 14 | |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | — | | | | — | | | | — | | | | — | | | | — | |
| Revenues | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | — | | | $ | — | | | $ | — | | | $ | 3 | | | $ | 3 | |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (3 | ) | | | — | | | | — | | | | — | | | | (3 | ) |
| Revenues | | | (5 | ) | | | — | | | | — | | | | — | | | | (5 | ) |
| Fuel Expense | | | — | | | | — | | | | — | | | | (4 | ) | | | (4 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months Ended June 30 |
| | | Power Contracts | | FTRs | | Interest Rate Swaps | | Other | | Total |
| | | (In millions) |
| Derivatives in a Hedging Relationship | | | | | | | | | | |
| | | | | | | | | | | |
| 2012 | | | | | | | | | | |
| Gain (Loss) Recognized in AOCI (Effective Portion) | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| | | | | | | | | | | |
| 2011 | | | | | | | | | | |
| Gain (Loss) Recognized in AOCI (Effective Portion) | | $ | 14 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 14 |
|
| | | | | | | | | | | |
Derivatives Not in a Hedging Relationship | | | | | | | | | | |
| | | | | | | | | | | |
| 2012 | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | |
| Other Operating Expense | | $ | 7 |
| | $ | 12 |
| | $ | — |
| | $ | 5 |
| | $ | 24 |
|
| Interest Expense | | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
| | | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
| Purchased Power Expense | | $ | (104 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (104 | ) |
| Revenues | | 95 |
| | 5 |
| | — |
| | — |
| | 100 |
|
| Other Operating Expense | | — |
| | (18 | ) | | — |
| | — |
| | (18 | ) |
| Fuel Expense | | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Interest Expense | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | |
2011 | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | |
| Purchase Power Expense | | $ | 33 | | $ | — | | $ | — | | $ | — | | $ | 33 | | |
| Purchased Power Expense | | $ | 33 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 33 |
|
| Revenues | | | (4 | ) | | — | | — | | — | | | (4 | ) | (4 | ) | | — |
| | — |
| | — |
| | (4 | ) |
| Other Operating Expense | | | (34 | ) | | 13 | | — | | — | | | (21 | ) | (34 | ) | | 11 |
| | — |
| | — |
| | (23 | ) |
| Interest Expense | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | |
| Purchase Power Expense | | 1 | | — | | — | | — | | 1 | | |
| Purchased Power Expense | | $ | 1 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 1 |
|
| Revenues | | | (39 | ) | | 18 | | — | | — | | | (21 | ) | (39 | ) | | 13 |
| | — |
| | — |
| | (26 | ) |
| Other Operating Expense | | — | | | (59 | ) | | — | | — | | | (59 | ) | — |
| | (40 | ) | | — |
| | — |
| | (40 | ) |
| | | |
2010 | | |
| Unrealized Gain (Loss) Recognized in: | | |
| Purchase Power Expense | | $ | 66 | | $ | — | | $ | — | | $ | — | | $ | 66 | | |
| | | |
| Realized Gain (Loss) Reclassified to: | | |
| Purchase Power Expense | | | (26 | ) | | — | | — | | — | | | (26 | ) | |
| Interest Expense | | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | | | | |
| Derivatives Not in a Hedging | | Three Months Ended June 30, | |
| Relationship with Regulatory Offset(2) | | NUGs | | | Other | | | Total | |
| | | (In millions) | |
2011 | | | | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument: | | $ | (147 | ) | | $ | 2 | | | $ | (145 | ) |
| Unrealized Gain (Loss) to Regulatory Assets: | | | 147 | | | | (2 | ) | | | 145 | |
| |
| Realized Gain (Loss) to Derivative Instrument: | | | 62 | | | | — | | | | 62 | |
| Realized Gain (Loss) to Regulatory Assets: | | | (62 | ) | | | — | | | | (62 | ) |
| |
2010 | | | | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument: | | $ | (35 | ) | | | — | | | $ | (35 | ) |
| Unrealized Gain (Loss) to Regulatory Assets: | | | 35 | | | | — | | | | 35 | |
| |
| Realized Gain (Loss) to Derivative Instrument: | | | 68 | | | | — | | | | 68 | |
| Realized Gain (Loss) to Regulatory Assets: | | | (68 | ) | | | — | | | | (68 | ) |
48
| | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, | |
| | | Power | | | | | | | Interest | | | | | | | |
| | | Contracts | | | FTRs | | | Rate Swaps | | | Other | | | Total | |
| | | (In millions) | |
Derivatives in a Hedging Relationship | | | | | | | | | | | | | | | | | | | | |
2011 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | 5 | | | $ | — | | | $ | — | | | $ | — | | | $ | 5 | |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | 16 | | | | — | | | | — | | | | — | | | | 16 | |
| Revenues | | | (12 | ) | | | — | | | | — | | | | — | | | | (12 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | | | | | | | | | | | | | | | | | | | |
| Gain (Loss) Recognized in AOCL (Effective Portion) | | $ | (2 | ) | | $ | — | | | $ | — | | | $ | 6 | | | $ | 4 | |
Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (7 | ) | | | — | | | | — | | | | — | | | | (7 | ) |
| Revenues | | | (5 | ) | | | — | | | | — | | | | — | | | | (5 | ) |
| Fuel Expense | | | — | | | | — | | | | — | | | | (8 | ) | | | (8 | ) |
| | | | | | | | | | | | | | | | | | | | | |
Derivatives Not in a Hedging Relationship | | | | | | | | | | | | | | | | | | | | |
2011 | | | | | | | | | | | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | $ | 61 | | | $ | — | | | $ | — | | | $ | — | | | $ | 61 | |
| Revenues | | | (3 | ) | | | — | | | | — | | | | — | | | | (3 | ) |
| Other Operating Expense | | | (54 | ) | | | 13 | | | | 1 | | | | — | | | | (40 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (36 | ) | | | — | | | | — | | | | — | | | | (36 | ) |
| Revenues | | | (29 | ) | | | 26 | | | | — | | | | — | | | | (3 | ) |
| Other Operating Expense | | | — | | | | (87 | ) | | | — | | | | — | | | | (87 | ) |
| | | | | | | | | | | | | | | | | | | | | |
2010 | | | | | | | | | | | | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | $ | 39 | | | $ | — | | | $ | — | | | $ | — | | | $ | 39 | |
| | | | | | | | | | | | | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | |
| Purchase Power Expense | | | (49 | ) | | | — | | | | — | | | | — | | | | (49 | ) |
| | | | | | | | | | | | | |
| Derivatives Not in a Hedging | | Six Months Ended June 30, | |
| Relationship with Regulatory Offset(2) | | NUGs | | | Other | | | Total | |
| | | (In millions) | |
2011 | | | | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument: | | $ | (236 | ) | | $ | 2 | | | $ | (234 | ) |
| Unrealized Gain (Loss) to Regulatory Assets: | | | 236 | | | | (2 | ) | | | 234 | |
| | | | | | | | | | | | | |
| Realized Gain (Loss) to Derivative Instrument: | | | 134 | | | | (10 | ) | | | 124 | |
| Realized Gain (Loss) to Regulatory Assets: | | | (134 | ) | | | 10 | | | | (124 | ) |
| | | | | | | | | | | | | |
2010 | | | | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument: | | $ | (259 | ) | | | — | | | $ | (259 | ) |
| Unrealized Gain (Loss) to Regulatory Assets: | | | 259 | | | | — | | | | 259 | |
| | | | | | | | | | | | | |
| Realized Gain (Loss) to Derivative Instrument: | | | 146 | | | | (9 | ) | | | 137 | |
| Realized Gain (Loss) to Regulatory Assets: | | | (146 | ) | | | 9 | | | | (137 | ) |
| | |
(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. |
49
|
| | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30 |
| | Power Contracts | | FTRs | | Interest Rate Swaps | | Other | | Total |
| | (In millions) |
| Derivatives in a Hedging Relationship | | | | | | | | | |
| | | | | | | | | | |
| 2012 | | | | | | | | | |
| Gain (Loss) Recognized in AOCI (Effective Portion) | $ | (4 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (4 | ) |
| | | | | | | | | | |
| 2011 | | | | | | | | | |
| Gain (Loss) Recognized in AOCI (Effective Portion) | $ | 5 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 5 |
|
| Effective Gain (Loss) Reclassified to: | | | | | | | | | |
| Purchased Power Expense | 16 |
| | — |
| | — |
| | — |
| | 16 |
|
| Revenues | (12 | ) | | — |
| | — |
| | — |
| | (12 | ) |
| Fuel Expense | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| Derivatives Not in a Hedging Relationship | | | | | | | | | |
| | | | | | | | | | |
| 2012 | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | |
| Other Operating Expense | $ | 62 |
| | $ | 17 |
| | $ | — |
| | $ | 3 |
| | $ | 82 |
|
| Interest Expense | — |
| | — |
| | (20 | ) | | — |
| | (20 | ) |
| | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | |
| Purchased Power Expense | $ | (221 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (221 | ) |
| Revenues | 206 |
| | 11 |
| | — |
| | — |
| | 217 |
|
| Other Operating Expense | — |
| | (41 | ) | | — |
| | — |
| | (41 | ) |
| Fuel Expense | — |
| | — |
| | — |
| | (1 | ) | | (1 | ) |
| Interest Expense | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| 2011 | | | | | | | | | |
| Unrealized Gain (Loss) Recognized in: | | | | | | | | | |
| Purchased Power Expense | $ | 61 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 61 |
|
| Revenues | (3 | ) | | — |
| | — |
| | — |
| | (3 | ) |
| Other Operating Expense | (54 | ) | | 12 |
| | 1 |
| | — |
| | (41 | ) |
| Interest Expense | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| Realized Gain (Loss) Reclassified to: | | | | | | | | | |
| Purchased Power Expense | $ | (36 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (36 | ) |
| Revenues | (29 | ) | | 16 |
| | (1 | ) | | — |
| | (14 | ) |
| Other Operating Expense | — |
| | (54 | ) | | — |
| | — |
| | (54 | ) |
| Interest Expense | — |
| | — |
| | — |
| | — |
| | — |
|
The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2012 and 2011, are summarized in the following tables:
|
| | | | | | | | | | | | | | | | | | | |
| | Three Months Ended June 30 |
| | NUGs | | LCAPP | | Regulated FTRs | | Other | | Total |
| | (In millions) |
| Derivatives Not in a Hedging Relationship with Regulatory Offset | | | | | | | | | |
| | | | | | | | | | |
| 2012 | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument | $ | (54 | ) | | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | (199 | ) |
| Realized Gain (Loss) to Derivative Instrument | 61 |
| | — |
| | 5 |
| | — |
| | 66 |
|
| | | | | | | | | | |
| 2011 | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument | $ | (147 | ) | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | (145 | ) |
| Realized Gain (Loss) to Derivative Instrument | 62 |
| | — |
| | — |
| | — |
| | 62 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Six Months Ended June 30 |
| | NUGs | | LCAPP | | Regulated FTRs | | Other | | Total |
| | (In millions) |
| Derivatives Not in a Hedging Relationship with Regulatory Offset | | | | | | | | | |
| | | | | | | | | | |
| 2012 | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument | $ | (133 | ) | | $ | (145 | ) | | $ | (1 | ) | | $ | — |
| | $ | (279 | ) |
| Realized Gain (Loss) to Derivative Instrument | 133 |
| | — |
| | 9 |
| | — |
| | 142 |
|
| | | | | | | | | | |
| 2011 | | | | | | | | | |
| Unrealized Gain (Loss) to Derivative Instrument | $ | (236 | ) | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | (234 | ) |
| Realized Gain (Loss) to Derivative Instrument | 134 |
| | — |
| | (10 | ) | | — |
| | 124 |
|
The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or refundcredit to) customers during the three months and six months ended June 30, 20112012 and 2010:2011:
| | | | | | | | | | | | | |
| | | Three Months Ended June 30, | |
| Derivatives Not in a Hedging Relationship with Regulatory Offset(1) | | NUGs | | | Other | | | Total | |
| | | (In millions) | |
| Outstanding net asset (liability) as of April 1, 2011 | | $ | (362 | ) | | $ | — | | | $ | (362 | ) |
| Additions/Change in value of existing contracts | | | (147 | ) | | | 2 | | | | (145 | ) |
| Settled contracts | | | 62 | | | | — | | | | 62 | |
| | | | | | | | | | |
| Outstanding net asset (liability) as of June 30, 2011 | | $ | (447 | ) | | $ | 2 | | | $ | (445 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| Outstanding net asset (liability) as of April 1, 2010 | | $ | (590 | ) | | $ | 10 | | | $ | (580 | ) |
| Additions/Change in value of existing contracts | | | (35 | ) | | | — | | | | (35 | ) |
| Settled contracts | | | 68 | | | | — | | | | 68 | |
| | | | | | | | | | |
| Outstanding net asset (liability) as of June 30, 2010 | | $ | (557 | ) | | $ | 10 | | | $ | (547 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30, | | | Three Months Ended June 30 |
| Derivatives Not in a Hedging Relationship with Regulatory Offset(1) | | NUGs | | Other | | Total | | | NUGs | | LCAPP | | Regulated FTRs | | Other | | Total |
| | | (In millions) | | | (In millions) |
| Outstanding net asset (liability) as of January 1, 2011 | | $ | (345 | ) | | $ | 10 | | $ | (335 | ) | |
| Outstanding net asset (liability) as of April 1, 2012 | | | $ | (300 | ) | | $ | — |
| | $ | (5 | ) | | $ | — |
| | $ | (305 | ) |
| Additions/Change in value of existing contracts | | | (236 | ) | | 2 | | | (234 | ) | | (54 | ) | | (145 | ) | | — |
| | — |
| | (199 | ) |
| Settled contracts | | 134 | | | (10 | ) | | 124 | | | 61 |
| | — |
| | 5 |
| | — |
| | 66 |
|
| Outstanding net asset (liability) as of June 30, 2012 | | | $ | (293 | ) | | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | (438 | ) |
| | | | | | | | | | | | | | | | | | |
| Outstanding net asset (liability) as of June 30, 2011 | | $ | (447 | ) | | $ | 2 | | $ | (445 | ) | |
| | | | | | | | | |
| | | |
| Outstanding net asset (liability) as of January 1, 2010 | | $ | (444 | ) | | $ | 19 | | $ | (425 | ) | |
| Outstanding net asset (liability) as of April 1, 2011 | | | $ | (362 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (362 | ) |
| Additions/Change in value of existing contracts | | | (259 | ) | | — | | | (259 | ) | | (147 | ) | | — |
| | 2 |
| | — |
| | (145 | ) |
| Settled contracts | | 146 | | | (9 | ) | | 137 | | | 62 |
| | — |
| | — |
| | — |
| | 62 |
|
| | | | | | | | | |
| Outstanding net asset (liability) as of June 30, 2010 | | $ | (557 | ) | | $ | 10 | | $ | (547 | ) | |
| | | | | | | | | |
| Outstanding net asset (liability) as of June 30, 2011 | | | $ | (447 | ) | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | (445 | ) |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Six Months Ended June 30 |
Derivatives Not in a Hedging Relationship with Regulatory Offset(1) | | NUGs | | LCAPP | | Regulated FTRs | | Other | | Total |
| | | (In millions) |
| Outstanding net asset (liability) as of January 1, 2012 | | $ | (293 | ) | | $ | — |
| | $ | (8 | ) | | $ | — |
| | $ | (301 | ) |
| Additions/Change in value of existing contracts | | (133 | ) | | (145 | ) | | (1 | ) | | — |
| | (279 | ) |
| Settled contracts | | 133 |
| | — |
| | 9 |
| | — |
| | 142 |
|
| Outstanding net asset (liability) as of June 30, 2012 | | $ | (293 | ) | | $ | (145 | ) | | $ | — |
| | $ | — |
| | $ | (438 | ) |
| | | | | | | | | | | |
| Outstanding net asset (liability) as of January 1, 2011 | | $ | (345 | ) | | $ | — |
| | $ | — |
| | $ | 10 |
| | $ | (335 | ) |
| Additions/Change in value of existing contracts | | (236 | ) | | — |
| | 2 |
| | — |
| | (234 | ) |
| Settled contracts | | 134 |
| | — |
| | — |
| | (10 | ) | | 124 |
|
| Outstanding net asset (liability) as of June 30, 2011 | | $ | (447 | ) | | $ | — |
| | $ | 2 |
| | $ | — |
| | $ | (445 | ) |
| | |
(1) | | Changes in the fair value of certain contracts are deferred for future recovery from (or refundcredited to) customers. |
8. REGULATORY MATTERS
6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially allSTATE REGULATION
Each of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on yearsthe Utilities' retail rates, conditions of service, issuance of securities and compensation levels.
FirstEnergy provides a portionother matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of non-contributory pre-retirement basic life insurance for employees whoPE in Virginia are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirementsubject to certain employees, their dependentsregulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
MARYLAND
PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
FirstEnergy’s funding policyregulations, and statutory provisions. SOS supply is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively,competitively procured in the last two quartersform of 2011.
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As resultrolling contracts of varying lengths through periodic auctions overseen by the MDPSC and a third party monitor. The settlements with respect to residential SOS for PE customers expire on December 31, 2012, but by statute service will continue in the same manner unless changed by order of the mergerMDPSC. The settlement provisions relating to non-residential service have expired but, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by10%and reduce electricity demand by15%, in each case by 2015. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsix-year period. Maryland law only allows for the utility to recover lost distribution revenue attributable to the energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE.Meanwhile, after extensive meetings with Allegheny, FirstEnergy assumed certain pensionthe MDPSC Staff and OPEB plans. FirstEnergy measuredother stakeholders, on August 31, 2011, PE filed a new comprehensive plan that includes additional and improved programs for the funded status ofperiod 2012-2014.The plan is expected to cost approximately$66 millionover 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. three-year period.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,MDPSC held hearings on PE and the actuarially determined benefit obligations for suchother utilities' plans as of that date were $1,341 millionin October 2011, and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods inDecember 22, 2011, subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s postretirement benefit plans other than pensions.
The components of the consolidated net periodic cost for pension and OPEB benefits (including amounts capitalized) were as follows:
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| Pension Benefit Cost (Credit) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| Service cost | | $ | 34 | | | $ | 25 | | | $ | 62 | | | $ | 49 | |
| Interest cost | | | 97 | | | | 79 | | | | 181 | | | | 157 | |
| Expected return on plan assets | | | (115 | ) | | | (90 | ) | | | (216 | ) | | | (181 | ) |
| Amortization of prior service cost | | | 4 | | | | 3 | | | | 7 | | | | 6 | |
| Recognized net actuarial loss | | | 48 | | | | 47 | | | | 97 | | | | 94 | |
Curtailments(1) | | | — | | | | — | | | | (2 | ) | | | — | |
Special termination benefits(1) | | | — | | | | — | | | | 9 | | | | — | |
| | | | | | | | | | | | | |
| Net periodic cost | | $ | 68 | | | $ | 64 | | | $ | 138 | | | $ | 125 | |
| | | | | | | | | | | | | |
| | |
(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 | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| Other Postretirement Benefit Cost (Credit) | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| Service cost | | $ | 3 | | | $ | 3 | | | $ | 7 | | | $ | 5 | |
| Interest cost | | | 12 | | | | 11 | | | | 23 | | | | 22 | |
| Expected return on plan assets | | | (10 | ) | | | (9 | ) | | | (20 | ) | | | (18 | ) |
| Amortization of prior service cost | | | (52 | ) | | | (48 | ) | | | (100 | ) | | | (96 | ) |
| Recognized net actuarial loss | | | 14 | | | | 15 | | | | 28 | | | | 30 | |
| | | | | | | | | | | | | |
| Net periodic cost (credit) | | $ | (33 | ) | | $ | (28 | ) | | $ | (62 | ) | | $ | (57 | ) |
| | | | | | | | | | | | | |
Pension and OPEB obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic OPEB (including amounts capitalized) recognized by FirstEnergy’s subsidiaries were as follows:
| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| Pension Benefit Cost | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| FES | | $ | 22 | | | $ | 22 | | | $ | 43 | | | $ | 44 | |
| OE | | | 5 | | | | 6 | | | | 11 | | | | 11 | |
| CEI | | | 5 | | | | 5 | | | | 10 | | | | 11 | |
| TE | | | 2 | | | | 2 | | | | 3 | | | | 4 | |
| JCP&L | | | 5 | | | | 6 | | | | 11 | | | | 12 | |
| Met-Ed | | | 3 | | | | 3 | | | | 5 | | | | 5 | |
| Penelec | | | 4 | | | | 5 | | | | 9 | | | | 9 | |
| Other FirstEnergy Subsidiaries | | | 22 | | | | 15 | | | | 46 | | | | 29 | |
| | | | | | | | | | | | | |
| | | $ | 68 | | | $ | 64 | | | $ | 138 | | | $ | 125 | |
| | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| Other Postretirement Benefit Credit | | 2011 | | | 2010 | | | 2011 | | | 2010 | |
| | | (In millions) | |
| FES | | $ | (8 | ) | | $ | (7 | ) | | $ | (14 | ) | | $ | (13 | ) |
| OE | | | (5 | ) | | | (6 | ) | | | (12 | ) | | | (12 | ) |
| CEI | | | (2 | ) | | | (1 | ) | | | (3 | ) | | | (3 | ) |
| TE | | | — | | | | — | | | | (1 | ) | | | (1 | ) |
| JCP&L | | | (2 | ) | | | (2 | ) | | | (3 | ) | | | (4 | ) |
| Met-Ed | | | (2 | ) | | | (2 | ) | | | (5 | ) | | | (4 | ) |
| Penelec | | | (2 | ) | | | (2 | ) | | | (5 | ) | | | (4 | ) |
| Other FirstEnergy Subsidiaries | | | (12 | ) | | | (8 | ) | | | (19 | ) | | | (16 | ) |
| | | | | | | | | | | | | |
| | | $ | (33 | ) | | $ | (28 | ) | | $ | (62 | ) | | $ | (57 | ) |
| | | | | | | | | | | | | |
7. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries perform qualitative analyses 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.
VIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $295 million was outstanding as of June 30, 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 primarily the result of net losses of the noncontrolling interests ($15 million) and distributions to owners ($4 million) during the six months ended June 30, 2011.
In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.
PATH-WV
PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was 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 $27 million at June 30, 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 if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to 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 four of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
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Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. 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 June 30, 2011, were $55 million, $47 million and $21 million for JCP&L, PE and WP, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the three months and six months ended June 30, 2010 were $53 million and $117 million, respectively.
In 1998 the PPUC issued an order approving PE's plan with various modifications and follow-up assignments.
Pursuant to a transition plan for WPbill passed by the Maryland legislature, the MDPSC proposed rules, based on the product of a working group of utilities, regulators, and other interested stakeholders, that disallowed certain costs, including an estimated amount for an adverse power purchase commitmentcreate specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The bill requires that the NUG entityMDPSC consider cost-effectiveness, and provides that WPthe MDPSC may hold a variable interest,adopt different standards for which WP has taken the scope exception. As of June 30, 2011, WP’s reserve for this adverse purchase power commitment was $59 million, including a current liability of $11 million,different utilities based on such factors as system design and is being amortized over the life of the commitment.
Loss Contingencies
FirstEnergy has variable interestsexisting infrastructure, geography, and customer density. Beginning in certain sale and leaseback transactions. FirstEnergy is not the primary beneficiary of these interests as it does not have control over the significant activities affecting the economics of the arrangement.
FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of June 30, 2011:
| | | | | | | | | | | | | |
| | | Maximum | | | Discounted Lease | | | Net | |
| | | Exposure | | | Payments, net(1) | | | Exposure | |
| | | (In millions) | |
| FES | | $ | 1,348 | | | $ | 1,156 | | | $ | 192 | |
| OE | | | 635 | | | | 445 | | | | 190 | |
CEI(2) | | | 624 | | | | 69 | | | | 555 | |
TE(2) | | | 624 | | | | 303 | | | | 321 | |
| | |
(1) | | The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion. |
|
(2) | | CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements. |
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’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. During the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate for the second quarter and first six months of 2011. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first six months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs for tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net income tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the income tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.
As of June 30, 2011, it is reasonably possible that approximately $46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $4 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.
FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The interest associated with the settlement of the claim noted above favorably affected FirstEnergy’s effective tax rate by $6 million in the first half of 2011. During the first six months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest as a result of the merger with Allegheny. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $11 million in the first six months of 2010. The net amount of interest accrued as of June 30, 2011 was $10 million, compared with $3 million as of December 31, 2010.
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As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $28 million in the first six months 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 in March 2010, beginning inJuly 2013, the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. That charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.
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. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.
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 June 30, 2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.6 billion), and surety bonds and LOCs ($0.4 billion).
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees of $0.2 billion (included in the $0.8 billion discussed above) as of June 30, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.
While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $625 million, consisting of $522 million due to a below investment grade credit rating (of which $265 million is due to an acceleration of payment or funding obligation) and $103 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 $666 million.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $136 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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $138 million and $2 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 $17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.
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FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would 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 due in October 2012. 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.
(B) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergyMDPSC is required to meet federally-approved SO2assess each utility's compliance with the new rules, and NOx emissions regulations undermay assess penalties of up to$25,000per day, per violation.Further comments were filed regarding the CAA. FirstEnergy complies with SO2proposed rules on March 26, 2012, and NOx reduction requirements underat a hearing on April 17, 2012, 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 can result in the shutdownMDPSC approved re-publication of the generating unit involved and/or civil or criminal penalties.rules as final.
NEW JERSEY
JCP&L currently provides BGS for retail customers that do not choose a third party electric generation supplier and for customers of third party electric generation suppliers that fail to provide the contracted service. The supply for BGS, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for
larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The most recent BGS auction results, for supply commencing June 1, 2012, were approved by the NJBPU on February 9, 2012.
On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable.In its written Order issued July 2008, three complaints were filed against FGCO in31, 2012, affirming the U.S. District Court fordetermination made at its July 18, 2012 agenda meeting, the Western DistrictNJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of Pennsylvania seeking damages based on coal-fired Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudentsafe, adequate and proper manner,” one beingutility service to its customers" and ordered JCP&L to file a complaint filedbase rate case using a historical 2011 test year on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.
The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Unitsor before November 1, and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, the Court granted Met-Ed’s motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed2012. JCP&L is unable to predict the outcome of this matter.
In January 2009,
Pursuant to a formal Notice issued by the EPA issued a NOVNJBPU on September 14, 2011, public hearings were held to GenOn Energy, Inc. alleging NSR violations atsolicit comments regarding the Portland coal-fired plant based on “modifications” dating backstate of preparedness and responsiveness of the EDCs prior to, 1986. On Marchduring, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. On December 14, 2011, the EPA proposed emissions limitsNJBPU Staff filed a report of its preliminary findings and compliance schedulesrecommendations with respect to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted byelectric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey under Section 126EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the report of the CAA. consultant is due to be submitted to the NJBPU in August 2012.The NOVNJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.
OHIO
The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:
Generation supplied through a CBP commencing June 1, 2011;
A load cap of no less than80%, so that no single supplier is awarded more than80%of the tranches, which also alleged NSR violations atapplies to tranches assigned post-auction;
A6%generation discount to certain low income customers provided by the KeystoneOhio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);
No increase in base distribution rates through May 31, 2014; and Shawville coal-fired plants based
A new distribution rider, Rider DCR, to recover a return of, and on, “modifications” dating backcapital investments in the delivery system.
The Ohio Companies also agreed not to 1984. Met-Ed, JCP&L,recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the former ownerlonger of 16.67%the five-year period from June 1, 2011 through May 31, 2016 or when the amount of Keystone, and Penelec, as former owner and operatorcosts avoided by customers for certain types of Shawville, are unable to predictproducts totals$360 milliondependent on the outcome of this matter.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 and alternative energy requirements.
In June 2008,
On April 13, 2012, the EPA issued a NoticeOhio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012.
As approved, the ESP 3 plan will maintain the substantial benefits from the current ESP including:
Freezing current base distribution rates through May 31, 2016;
Continuing to provide economic development and Finding of Violationassistance to Mission Energy Westside, Inc. (Mission) alleging that “modifications”low-income customers for the two-year extension period at the coal-fired Homer City Plant occurred from 1988levels established in the existing ESP;
Providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;
Continuing to the present without preconstruction NSR permitting in violationprovide power to shopping and to non-shopping customers as part of the CAA’s PSD program. market-based price set through an auction process; and
Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.
As approved, the ESP 3 plan will provide additional new benefits, including:
Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and
Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.
The filing is supported by19parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).Sevenadditional parties agreed not to oppose the filing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total
annual energy savings equivalent of approximately1,211GWHs in 2012 (an increase of416,000MWHs over 2011 levels),1,726GWHs in 2013,2,306GWHs in 2014 and2,903GWHs for each year thereafter through 2025.Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75% reduction each year thereafter through 2018.
In May 2010,December 2009, the EPAOhio Companies filed theirthree-year portfolio plan, as required by SB221, seeking approval for the programs they intended to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. In March 2011, the PUCO issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporationan Opinion and others thatOrder generally approving the Ohio Companies' 2010-2012 portfolio plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies have had an ownership interest in Homer City containing in all material respects allegations identical toimplemented those programs included in the plan. However, due to the timing of the approval of the plan, the Ohio Companies requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks for 2010. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the issue was moot for CEI and TE because they achieved their targets in that year. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO.
The Ohio Companies had filed applications for rehearing regarding portions of the PUCO's decision related to the Ohio Companies'three-year portfolio plan, which was later denied. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, which was dismissed on June 20, 2012. In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their next three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.
Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. The PUCO selected auditors to perform a financial and management audit, and final audit reports are currently scheduled to be filed with the PUCO on August 15, 2012. In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies have achieved their in-state solar compliance requirements for 2012.
PENNSYLVANIA
The Pennsylvania Companies currently operate under DSPs that expire May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative electric generation supplier or for customers of alternative electric generation suppliers that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On November 17, 2011, the Pennsylvania Companies filed a Joint Petition for Approval of their DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015.The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. Exceptions to the Recommended Decision are currently pending.A final order must be entered by the PPUC by August 17, 2012.
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, NOV. Inand directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN began to refund those amounts to customers in January 2011, and the DOJrefunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission losses are refunded. In April 2010, ME and PN filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME and PN TSC riders. ME and PN filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint against Penelecseeking relief in the U.S. District Court for the WesternEastern District of Pennsylvania, seeking injunctive relief against Penelec basedwhich was subsequently amended. The PPUC filed a Motion to Dismiss ME and PN Amended Complaint on alleged “modifications” at Homer City between 1991September 15, 2011 to 1994 without preconstruction NSR permitting in violationwhich ME and PN responded and which remains pending.On February 28, 2012, the Supreme Court of Pennsylvania denied the Petition for Allowance of Appeal.On June 27, 2012, ME and PN filed a Petition for Writ of Certiorari with the Supreme Court of the CAA’s PSD and Title V permitting programs.United States. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against PenelecPPUC's brief in opposition is due on August 31, 2012, and the other entities described aboveME/PE reply is due on September 10, 2012. If the Supreme Court declines to take the case then ME and PE will pursue their claims in the proceedings that are pending in the U.S. District Court (E.D. PA).
In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN's annual updates to their TSC rider for the Western Districtannual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of Pennsylvania seeking damages based on Homer City’s air emissionsmarginal transmission losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as well as certification as a class action anddescribed
above. The PPUC's approval in May 2010 authorized an increase to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intendsTSC for ME's customers to defend itself againstprovide for full recovery by December 31, 2010. Although the allegations made in the complaint, but,ultimate outcome of this matter cannot be determined at this time, ME and PN believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 millionin marginal transmission losses for the period prior to January 1, 2011.
Pennsylvania adopted Act 129 in 2008 to 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 (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter. matter or estimate any possible loss or range of loss.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of ME, PN and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements. On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding, and the ALJ's Recommended Decision was issued on April 19, 2012, recommending that the Joint Settlement be adopted as filed.The PPUC entered an order on May 10, 2012 approving the Joint Settlement.
In addition, Act 129 required utilities to file a SMIP with the CommonwealthPPUC. 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 its previously approved smart meter deployment plan and certain smart meter dependent aspects of the EE&C Plan. WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. WP also proposed to take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. 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. A joint settlement with all parties based on these terms, with one party retaining the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan, was approved by the PPUC on June 30, 2011. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file by the end of 2012, or in a future base distribution rate case.The deadline for the Pennsylvania Companies to file their smart meter deployment plan is December 31, 2012.
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. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the PPUC entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming DSPs, including: the duration of the programs and the length of associated energy contracts; a customer referral program; a retail opt-in auction; time-of-use rate options provided through contracts with electric generation suppliers; and periodic rate adjustments.Following the issuance of a Tentative Order and comments filed by various parties, the PPUC entered a final order on March 2, 2012 outlining an intermediate work plan. Several suggested models for long-range default service have been presented and were the topic of a March 2012 en banc hearing. It is expected that a tentative order will be issued for comment with a final long-range proposal.
The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by ME, PN, Penn, WP and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES, ME, PN, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on April 26, 2012, on the Statesproposed rulemaking, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of New Jersey
evidence demonstrating a need for them.
WEST VIRGINIA
In April 2010, MP and New York intervenedPE filed with the WVPSC a Joint Stipulation and haveAgreement of Settlement reached with the other parties in a proceeding for an annual increase in retail rates that provided for:
$40 millionannualized base rate increases effective June 29, 2010;
Deferral of February 2010 storm restoration expenses over a maximumfive-year period;
Additional$20 millionannualized base rate increase effective in January 2011;
Decrease of$20 millionin ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and
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 January 2011, MP and PE filed separate complaints regarding Homer Cityan application with the WVPSC seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec, the co-owner and operatorto certifythreefacilities as Qualified Energy Resource Facilities for purposes of Homer City priorcompliance with their approved plan pursuant to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claimsAREPA. The application was approved and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. The scopethreefacilities are capable of Penelec’s indemnity obligation to and from Mission is under dispute and Penelec is unable to predictgenerating renewable credits which will assist 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 coal-fired plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permittingcompanies in meeting their combined requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. 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.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR 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 this and a subsequent request but 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 plants: 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 coal-fired plants 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 Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A 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 filingsAREPA. Further, in February 2011, MP and plaintiffsPE filed their responses in April 2011. The parties are awaiting a decision frompetition with the District Court, but thereWVPSC seeking an order declaring that MP is no deadline forentitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that decision.
In September 2007, Allegheny also received a NOV from the EPA alleging NSRMP is required to purchase pursuant to electric energy purchase agreements between MP and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plantsthreeNUG facilities in West Virginia.
FirstEnergy intends to vigorously defend against The City of New Martinsville and Morgantown Energy Associates, each the CAA matters described above but cannot predict their outcomes.
State Air Quality Compliance
In early 2006, Maryland passedowner of one of 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 coal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the plant is vital to reliabilitycontracted resources, have participated in the Baltimore/Washington DC metropolitan area, which PJM determinedcase in 2006. Pursuantopposition to the legislation, the Maryland Departmentpetition. The WVPSC issued an order granting ownership 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 coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’s CAIR requires reductions of NOx and SO2 emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO2 emission allowances between power plants located in the same state and interstate trading of NOx and SO2 emission allowances with some restrictions. FGCO’s future cost of compliance may be substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of CSAPR, other environmental proposals and other factors on FirstEnergy’s competitive fossil generating facilities, including but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operations of its coal-fired plants.
Hazardous Air Pollutant Emissions
On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action takenall RECs produced by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’s operations may result.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, 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 (CO2) 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 that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; 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; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To 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.
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In 2009, the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.
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’s plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.
In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’s cooling water system). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In April 2011, the U.S. Attorney’s Office in Cleveland, Ohio 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.
In May 2011, theMP.The West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.
FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.
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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 coal-fired plant. 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 in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. 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. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately 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
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’s future cost of compliance with any coal combustion residuals regulations that 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 Little Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.
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The Utility 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 June 30, 2011, based on estimates of the total costs of cleanup, the Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $61 million) have been accrued through June 30, 2011. Included in the total are accrued liabilities of approximately $63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.
(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. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. In November 2010, the Supreme Court issued an Order on June 11, 2012, upholding the WVPSC's decision.
The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC alleging the WVPSC order denying Plaintiffs’ motion. The Court’s order effectively endsviolated PURPA and requested FERC initiate an enforcement action. On April 24, 2012, the class action attempt,FERC ruled that the FERC-jurisdictional contracts are intended to pay only for electric energy and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have yet to take any affirmative steps to pursue their individual claims.
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensurecapacity (and not for RECs), and that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of 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. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearingstate law controlled on the Davis-Besse license renewal applicationissues of determining which entity owns RECs and how they are transferred between entities. The FERC declined to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearingact on the Davis-Besse license renewal application.
On April 14, 2011, a groupcomplaints and instead noted that the City of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safetyNew Martinsville and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.
In January 2004, subsidiaries of FirstEnergy filed a lawsuitMorgantown Energy Associates could file complaints in the U.S. Court of Federal Claims seeking damagesDistrict Court.FERC also noted there may be language in connectionthe WVPSC decision that is inconsistent with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a resultPURPA. MP filed for rehearing of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel byFERC's order taking the Nuclear Waste Policy Act (42 USC 10101 et seq) andposition that 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 litigation of these claims. FirstEnergy filed damages schedules and disclosuresWVPSC order is consistent 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 review and audit by DOE.
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ICG Litigation
On December 28, 2006, AE Supply and MPPURPA. New Martinsville filed a complaint in the U.S. District Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV),on June 4, 2012, alleging that the WVPSC order violates PURPA.
On March 9, 2012, to assist the WVPSC with inquiries from public officials and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply andthe public, MP for the supply of coalprovided information to the Harrison generating facility. Prior toWVPSC in the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subjectform 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 from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clauseclosed entry filing in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.
Other Legal Matters
In February 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 customersENEC case 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 inplant deactivations. On April 2, 2012, the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case dueWVPSC issued an order requesting additional information from MP related to the lack of jurisdiction ofAlbright, Rivesville and Willow Island plant deactivation announcements. On April 30, 2012, MP provided the court of common pleas. WVPSC with additional information regarding the plant deactivations.The court grantedWVPSC issued an order on July 13, 2012 finding the motioninformation provided to dismiss on September 7, 2010. The plaintiffs appealed thebe sufficient and FirstEnergy's decision to deactivate the Court of Appeals of Ohio, which has not yet rendered an opinion.three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on FirstEnergy’s or its subsidiaries’ financial condition, results of operations and cash flows.RELIABILITY MATTERS
10. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO charged with establishingdesignated by FERC to establish and enforcingenforce these reliability standards, although itNERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation.RFC. All of FirstEnergy’sFirstEnergy's facilities are located within the ReliabilityFirstRFC region. FirstEnergy actively participates in the NERC and ReliabilityFirstRFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.RFC.
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.RFC. Moreover, it is clear that the NERC, ReliabilityFirstRFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Still, anyAny future inability on FirstEnergy’sFirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s&L's Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission
(transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up toelevenhours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s&L's contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests.On March 22, 2012, NERC concluded the investigation of the matter and forwarded it to NCEA for further review. NCEA is currently evaluating the findings of the investigation. JCP&L is not ableexpects the matter to predict what actions, if any, thatbe resolved for an immaterial amount.
In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the NERC may take with respectaudited systems and processes to this matter.
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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line. This event did not resultbe 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, although a final determination has not yet been made by FERC.
Allegheny has been subject to routine audits with respect to itsfull compliance with applicableall audited reliability standardsstandards. RFC will perform additional audits in 2012.
FERC MATTERS
PJM Transmission Rate
PJM and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain investigations with regard to certain matters of compliance by Allegheny.
(B) MARYLAND
By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. 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 order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedingsstakeholders have been set bydebating the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilitiesproper method to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the 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. 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 and those programs are to be filed by September 1, 2011.
In March 2009, the MDPSC 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. 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 summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.
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On March 24, 2011, the MDPSC 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. The Maryland legislature passed a bill on April 11, 2011, which 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 legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC 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 proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.
(C) NEW JERSEY
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). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).
(D) OHIO
The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies 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 (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI’s 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 and alternative energy requirements.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The 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. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and 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. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were 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 them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy
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requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On 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. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. 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 credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect 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 authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.
(E) PENNSYLVANIA
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 ofallocate costs for marginalnew transmission losses.facilities. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accountsmatter is contentious because costs for marginalfacilities built in one transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amountszone often are allocated to customers in January 2011,other transmission zones. During recent years, the debate has focused on the question of the methodology for determining the transmission zones and customers who benefit from a given facility and, if so, whether the refunds will continue overmethodology can determine the pro rata share of each zone's benefit. While FirstEnergy and other parties advocated for a 29 month period untiltraditional "beneficiary pays" approach, others advocate for “socializing” the full amounts previously recovered for marginal transmission loses are refunded. costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. This debate is framed by regulatory and court decisions.In April 2010, Met-Ed and Penelec filed a Petition for Review with2007, the CommonwealthU.S. Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying chargesAppeals for the periodSeventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of21, 2010, FERC set this matter cannot be determined at this time, Met-Edfor a “paper hearing” and Penelec believerequested parties to submit written comments. FERC identifiednineseparate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcomeallocation of the proceeding related tocost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 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 in 2008 to 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. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
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The PPUC entered an Order in February 2010 giving final approval to all aspectsmajority of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that 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 does not meet the Total 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 deployment, which the PPUC approved in January 2011.
Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the 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, 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 OCA 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 considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. 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 OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.
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By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, variouscosts. Subsequently, numerous parties filed responsive comments objecting to the above accounting method utilized by Met-Edor studies on May 28, 2010 and Penelec. 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. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted jointreply comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011,28, 2010. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.
(F) VIRGINIA
In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portionsuse of the PATH Project. beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis.On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. 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 WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 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;
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;
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 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. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.
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 and 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 and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.
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(H) FERC MATTERS
Rates for Transmission Service Between MISO and PJM
In November 2004,March 30, 2012, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initialon remand reaffirming its prior decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.
PJM Transmission Rate
In April 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costszone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order.
Order No. 1000 issued by FERC on July 21, 2011, requires the submission of a compliance filing in October 2012 by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission facilities that are rated at less than 500 kV, however, areprojects directed by the PJM Board of Managers satisfies the principles set forth in the order. The PJM transmission owners have announced their intention to submit a compliance filing based on a hybrid methodology of 50% beneficiary pays and 50% postage stamp (or socialization) to be allocatedeffective for projects approved by the PJM Board on a load flow methodology (DFAX), whichand after the effective date of the compliance filing. FirstEnergy is generally referredworking with other PJM transmission owners to as a “beneficiary pays” approach to allocatingdevelop the cost of high voltage transmission facilities.
FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and,required filing based on this finding, remanded the rate design issue back to FERC.proposed methodology.
In an order dated January 21, 2010, FERC set the matter for a “paper hearing"— meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone entered intotransferred from MISO to PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.
On February 1, 2011, ATSI in conjunction While most of the matters involved with PJM filed its proposal with FERCthe move have been resolved, the question of ATSI's responsibility for moving its transmission rate into PJM’s tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEPcertain costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose“Michigan Thumb” transmission project continues to be disputed; the details of effecting movement ofwhich dispute are discussed below in the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.
On May 31, 2011,"MISO Multi-Value Project Rule Proposal." In addition, FERC issued orders that address the proposed ATSI transmission rate, anddenied certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges forof ATSI's transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission ratesrate until such time as ATSI files and FERC approvessubmits a cost/benefit analysis that demonstrates net benefits to customers from the cost-benefit study. On June 30, 2011,move. ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requestedhas asked for rehearing of FERC’s decision to require a cost-benefit study analysisFERC's orders that address the Michigan Thumb transmission project, and the exit fee issue.
ATSI's filings and requests for rehearing on these matters, as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing,well as the pleadings submitted by parties that oppose ATSI's position are currently pending before FERC.
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From late April 2011 through June 2011, FERC issued other orders Finally, a negotiated agreement that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement betweenrequires ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreementa one-time charge of ATSI’s responsibility $1.8 millionfor certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. ATSI's exit, is pending before FERC.
The final outcome of those proceedings that address the remaining open issues related to ATSI’sATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.
MISO Multi-Value Project Rule Proposal
In July 2010, MISO and certain MISO transmission owners (not including ATSI or FirstEnergy) jointly filed with FERC theira proposed cost allocation methodology for certain new transmission projects. The new transmission projects—projects - described as MVPs —- are a class of transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.”MISO's MTEP process. Under MISO’sMISO's proposal, the costs of “Michigan Thumb” MVP projects that were approved by MISO’sMISO's Board prior to the June 1, 2011 effective date of FirstEnergy’sFirstEnergy's integration into PJM would
continue to be allocated to FirstEnergy.and charged to ATSI. MISO estimated that approximately $15$15 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone associated withupon completion of project construction.
FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project upon its completion.onto ATSI or onto ATSI's customers that assert legal, factual and policy arguments.To date, FERC has responded in a series of orders that require ATSI to absorb the charges for the Michigan Thumb Project.
In September 2010,
On October 31, 2011, FirstEnergy filed a protest toPetition of Review of certain of the MVP proposal arguing that MISO’s proposal to allocate costs of MVPs projects across the entire MISO footprint does not alignFERC's orders with the established rule that cost allocation isU.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit with briefs due from the parties through 2012 and oral argument to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that,scheduled in light2013.
In February 2012, FERC issued its most recent order (February 2012 Order) regarding the Michigan Thumb Project, in which FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of progress that had been madeMVP charges to date inATSI. MISO's Schedule 39 tariff is the ATSI integration into PJM, it would be unjust and unreasonablevehicle through which the MISO plans to allocate any MVPcharge the Michigan Thumb project costs to ATSI.FERC also set for hearing the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as toquestion of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligateit is just and reasonable for ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question ofMichigan Thumb project costs and, if so, the amount of costs that are to be allocated to ATSI or to load inand methodology for calculating ATSI's Michigan Thumb project cost responsibility.On March 28, 2012, FirstEnergy filed for clarification and rehearing of the ATSI zone were beyondFebruary 2012 Order, and such request is pending before the FERC.On July 10, 2012, a prehearing conference was convened before a FERC ALJ who will determine the scope of FERC’s orderthe hearing and would be addressed in future proceedings.thereafter set the hearing schedule.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost- benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.
FirstEnergy cannot predict the outcome of these proceedings at this time.or estimate the possible loss or range of loss.
PJM Underfunding FTR Complaint
On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets.Underfunding of the FTR contracts resulted in losses of approximately$35 million ($0.5 million - FES; $34.5 million - AE Supply) in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year are estimated to be approximately$11.5 million($11.4 million- FES;$0.1 million- AE Supply).
On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue.On March 2, 2012, FERC dismissed the complaint without prejudice, pending PJM's publication for stakeholder review and discussion, a report on the causes of the FTR underfunding and potential improvements, including modeling, which could be made to minimize the revenue inadequacy. On March 30, 2012, FES and AE Supply requested rehearing and reconsideration of the March 2, 2012 order.On July 19, 2012, FERC issued its Order on Rehearing and again dismissed FirstEnergy's complaint without prejudice. FERC noted PJM's ongoing stakeholder process and directed that if the issues were not addressed in that process FirstEnergy could file its complaint again.
FTR Allocation Complaint
On March 26, 2012, FES and AE Supply filed a complaint with FERC against PJM challenging PJM's FTR allocation rules. PJM allocates FTRs to load-serving entities in an annual allocation process, up to each LSE's peak load, based on the expected transmission capability for the upcoming planning year. If a transmission facility is scheduled to be out of service for a significant part of the year, it can result in LSEs' FTR allocations being reduced in the annual allocation. When these transmission facilities return to service during the year, PJM will create monthly FTRs to reflect the increased transmission capability during that month. However, instead of allocating these new monthly FTRs to the LSEs that were unable to obtain their full allocation of FTRs in the annual allocation process, PJM's rules instead require PJM to auction off these new monthly FTRs in the market. The complaint seeks a change to the PJM rules such that the new FTRs created each month by transmission lines returning to service would first be allocated to those LSEs that were denied a full allocation of their FTR entitlement in the annual allocation process before they are auctioned off in the market. On April 16, 2012, PJM filed its answer to the complaint. Exelon Corporation filed a protest, and several other parties filed comments.On July 11, 2012, FERC issued its Order Granting Complaint and Requiring a Compliance Filing. In the order, FERC agreed with FirstEnergy's description of the issues and with FirstEnergy's proposed changes to PJM's rules, and FERC directed PJM to submit a compliance filing within 60 days to implement the changes in the rules.
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)CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $190$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by 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 remandedoneof those proceedings to FERC, which arises out of claims previously filed with 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 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. On May 4, 2011, FERC affirmed the judge’sjudge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order.By Order issued June 13, 2012, FERC denied the request for rehearing. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals.
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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with 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 including AE Supply in this newadditional complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order.By Order issued June 13, 2012, that request for rehearing also was denied. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals. FirstEnergy cannot predict the outcome of this matter.either of the above matters or estimate the possible loss or range of loss.
PATH Transmission ExpansionProject
TrAIL Project.TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.
PATH Project.The PATH Project is comprised of a765kV transmission line that was 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. 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 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 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, affiliatesThe PJM Board has directed the PJM staff to perform additional analysis using the 2012 RTEP assumptions and incorporating the results of FirstEnergy and AEP filed motions or noticesthe May 2012 RPM base residual auction. The PJM staff is expected to withdrawreport its conclusions from this analysis to the Transmission Expansion Advisory Committee on August 9, 2012. All applications for authorization to construct the project that were pending beforefiled with state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. have been withdrawn.
Yards Creek
The WVPSC and VSCC have granted the motions 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 the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a 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 settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.
Seneca Pumped Storage Project Relicensing
The Seneca (Kinzua)Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. FERC issued a license for authorization to operate the project. The existing license expires on February 28, 2013.
In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the five-year ILP licensure process. FirstEnergy expects FERC to issue the new license before February 28, 2013. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca
The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’sFERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD)related documents in the license docket.
On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PADrelated documents necessary for themthe Seneca Nation to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’"competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.
The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to
include the dam and reservoir facilities operated by the U.S. Army Corps.Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’sFirstEnergy's petition, including motions to dismiss FirstEnergy’sFirstEnergy's petition. The “project boundary” issue is pending before FERC.
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The next steps in the relicensing process are forOn September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to definea finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and perform certain environmentalother parties about the data set, methodology and operational studies to support their respective applications. These steps are expected to runmodeling of the hydrological impacts of project operations.In March of 2012, FirstEnergy hosted a meeting as part of the consultation process. In that meeting, FirstEnergy reviewed its proposed methodology for conducting the hydrological impacts study and answered questions from third parties about the methodology. On April 11, 2012, the Seneca Nation and other parties filed comments on the proposed hydrologic impacts study.The study processes, including the discrete hydrological impacts study, will extend through approximately November of 2013.
FirstEnergy cannot predict the outcome of these proceedingsthis matter or estimate the possible loss or range of loss.
MISO Capacity Portability
On June 11, 2012, the FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO Stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. Comments are due on August 10, 2012, and reply comments are due on August 27, 2012. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including the prices at this time.which those auctions would clear. FirstEnergy anticipates submitting initial comments by August 10, 2012 and, depending on the comments submitted by other parties, submitting reply comments by August 27, 2012.
9. COMMITMENTS, GUARANTEES AND CONTINGENCIES
11. STOCK-BASED COMPENSATION PLANSGUARANTEES AND OTHER ASSURANCES
FirstEnergy has four typesvarious financial and performance guarantees and indemnifications which are issued in the normal course of stock-based compensation programs — LTIP, EDCP, ESOPbusiness. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and DCPD, as described below.
Allegheny’s stock-based awards were convertedindemnifications. FirstEnergy enters into FirstEnergy stock-based awards asthese arrangements to facilitate commercial transactions with third parties by enhancing the value of the datetransaction to the third party.
As of June 30, 2012, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of parental guarantees ($0.9 billion), subsidiaries' guarantees ($2.4 billion) and other guarantees ($0.7 billion).
Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. FES' debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO, and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
COLLATERAL AND CONTINGENT-RELATED FEATURES
As part of the merger. normal course of business, FirstEnergy and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuels, and emissions allowances. Certain bilateral agreements and derivative instruments contain provisions that require FirstEnergy or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FirstEnergy's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
Bilateral agreements and derivative instruments entered into by FirstEnergy and its subsidiaries have margining provisions that require posting of collateral.Based on FES' and AE Supply's power portfolio exposure as ofJune 30, 2012, FES has posted collateral of$36 million. The Regulated Distribution segment has posted collateral of$9 million.
These awards, referredcredit-risk-related contingent features stipulate that if the subsidiaries were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FirstEnergy or its
subsidiaries.The following chart discloses the additional credit contingent contractual obligations as converted Allegheny awards, were adjustedofJune 30, 2012:
|
| | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | AE Supply | | Utilities | | Total |
| | | (In millions) |
| Split Rating (One rating agency's rating below investment grade) | | $ | 373 |
| | $ | 6 |
| | $ | 40 |
| | $ | 419 |
|
| BB+/Ba1 Credit Ratings | | $ | 429 |
| | $ | 6 |
| | $ | 59 |
| | $ | 494 |
|
| Full impact of credit contingent contractual obligations | | $ | 658 |
| | $ | 73 |
| | $ | 73 |
| | $ | 804 |
|
Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Segment.As ofJune 30, 2012neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$46 millionand$13 million, respectively.
OTHER COMMITMENTS AND CONTINGENCIES
Signal Peak and Global Rail are borrowers under a$350 millionsyndicated two-year senior secured term loan facility due in termsOctober 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that originally shared ownership in the borrowers with FEV, have provided a guaranty of the number of awards and, where applicable,borrowers' obligations under the exercise price thereof, to reflectfacility. Following the merger’s common stock exchange ratio of 0.667sale of a shareportion of FEV's ownership interest in Signal Peak and Global Rail in the fourth quarter of 2011, FirstEnergy, common stock for each shareWMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding, continued to guarantee the borrowers' obligations under the current facility. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral.Global Holding is involved in negotiations to refinance the current facility with a bank facility under which it would be the borrower. In connection with such proposed refinancing, FirstEnergy expects to provide the new lenders with a guarantee of Allegheny common stock.Global Holding's obligations, and FirstEnergy and WMB Marketing Ventures, LLC expect to pledge not less than two-thirds of the equity interests in Global Holding and its subsidiaries.
(A) LTIPENVIRONMENTAL MATTERS
FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock
Various federal, state 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 stocklocal authorities regulate FirstEnergy with regard to air and restricted stock unitswater quality and other environmental matters. Compliance with environmental regulations could have currently been designateda material adverse effect on FirstEnergy's earnings and competitive position to be settled in common stock,the extent that FirstEnergy competes with vesting periods ranging from two monthscompanies that are not subject to ten years. Performance share awards are currently designated to be paid in cash rather than common stocksuch regulations and, therefore, do not countbear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and 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 or non-emitting plants and/or using emission allowances.
In July 2008,threecomplaints representing multiple plaintiffs were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf oftwenty-oneindividuals and the other is a class action complaint seeking certification as a class with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the limit on stock-based awards. There were 5.6 million shares available for future awards asallegations made in these complaints.
In December 2007, the states of June 30, 2011.
Restricted StockNew Jersey and Restricted Stock Units
Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:
| | | | |
| | Six Months | |
| | Ended | |
| | June 30, 2011 | |
| | | | |
Restricted stock and stock units outstanding as of January 1, 2011 | | | 1,878,022 | |
Granted | | | 891,881 | |
Converted Allegheny restricted stock | | | 645,197 | |
Exercised | | | (428,686 | ) |
Forfeited | | | (71,775 | ) |
| | | |
Restricted stock and stock units outstanding as of June 30, 2011 | | | 2,914,639 | |
| | | |
The 891,881 shares of restricted common stock granted duringConnecticut filed CAA citizen suits in the six months ended June 30, 2011 had a grant-date fair value of $33.2 million and a weighted-average vesting period of 2.74 years.
Restricted stock units include awards that will be settled in a specific number of shares of common 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 common stock based on FirstEnergy’s performance compared to annual target performance metrics.
Compensation expense recognized during the six months ended June 30, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $27 million and $20 million, respectively.
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Stock Options
Stock option activityU.S. District Court for the six months ended June 30, 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 | | | (691,304 | ) | | | 31.38 | |
| Options forfeited/expired | | | (78,978 | ) | | | 71.71 | |
| | | | | | | |
| Stock options outstanding as of June 30, 2011 | | | 4,586,717 | | | $ | 38.09 | |
| | | | | | | |
| (3,924,595 options exercisable) | | | | | | | | |
Compensation expense recognized for stock options duringEastern District of Pennsylvania alleging NSR violations at the six months ended June 30, 2011 was $0.3 million. No expense was recognized duringcoal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the six months ended June 30, 2010. Options granted during the six months ended June 30, 2011 had a grant-date fair value of $3.3 millioncurrent owner and an expected weighted-average vesting period of 3.79 years.
Options outstanding by exercise price as of June 30, 2011 were as follows:
| | | | | | | | | | | | | |
| | | | | | | Weighted | | | Remaining | |
| | | Shares Under | | | Average | | | Contractual | |
| Exercise Prices | | Options | | | Exercise Price | | | Life in Years | |
| | | | | | | | | | | | | |
| $20.02 – $30.74 | | | 1,045,122 | | | $ | 26.54 | | | | 2.02 | |
| $30.89 – $40.93 | | | 3,160,440 | | | | 37.30 | | | | 4.17 | |
| $42.72 – $51.82 | | | 3,883 | | | | 51.02 | | | | 0.70 | |
| $53.06 – $62.97 | | | 54,559 | | | | 56.15 | | | | 3.02 | |
| $64.52 – $71.82 | | | 9,042 | | | | 67.50 | | | | 5.24 | |
| $73.39 – $80.47 | | | 311,003 | | | | 80.17 | | | | 3.81 | |
| $81.19 – $89.59 | | | 2,668 | | | | 85.39 | | | | 6.09 | |
| | | | | | | | | | |
| Total | | | 4,586,717 | | | $ | 38.08 | | | | 3.64 | |
| | | | | | | | | | |
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 six months ended June 30, 2011 and 2010, net of amounts capitalized, totaled $2 million and $(6) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the six months ended June 30, 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 six months ended June 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, were $19 million and $10 million, respectively.
(C) EDCP
There was no material compensation expense recognized on EDCP stock units during the six months ended June 30, 2011 and 2010.
(D) DCPD
DCPD expenses recognized during the six months ended June 30, 2011 and 2010 were approximately $2 million in each period. The net liability recognized for DCPD of approximately $6 million as of June 30, 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 June 30, 2011.
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12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basisoperator), Sithe Energy (the purchaser of the net risk exposurePortland Station from ME in 1999) and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifiesME. Specifically, these suits allege that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The Court dismissed New Jersey's and Connecticut's claims for injunctive relief against ME, but denied ME's motion to dismiss the claims for civil penalties. The parties dispute the scope of ME's indemnity obligation to and from Sithe Energy. In February 2012, GenOn announced its plans to retire the Portland Station in January 2015 citing EPA emissions limits and compliance schedules to reduce SO2air emissions by approximately81%at the Portland Station by January 6, 2015.On July 27, 2012, FirstEnergy filed a motion for summary judgment arguing the Plaintiff's remaining claims for civil penalties are barred by the statute of limitations. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. ME, JCP&L and PN, as former owners of the facilities, are unable to predict the
outcome of this matter or estimate the possible loss or range of loss.
In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In addition, the Commonwealth of Pennsylvania and the classificationstates of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.
In June 2011, the FASB issued new accounting guidance that revises the manner in which entities presents comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is effective for FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.
13. SEGMENT INFORMATION
With the completion of the Allegheny merger in the first quarter of 2011, 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 used 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.
Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of 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/Corporate” 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 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 “Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.
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.
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, Pennsylvania, West Virginia, Maryland, New Jersey and New York intervened and purchases power for its POLR, SOShave filed separate complaints regarding Homer City seeking injunctive relief and default service requirements in Ohio,civil penalties. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the states of New Jersey and Maryland. This segment also includesNew York against all of the transmission operationsdefendants, including PN. In December 2011, the U.S., the Commonwealth of JCP&L, Met-Ed, Penelec, WP,Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. PN believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.
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 coal-fired plants. The EPA's NOV alleges equipment replacements during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. FGCO intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. In September 2007, AE 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 coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. On June 29, 2012, EPA issued another CAA section 114 request for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. FirstEnergy intends to vigorously defend against these CAA matters, but cannot predict their outcomes or estimate the possible loss or range of loss.
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, and PE and WP in the regulated electric generation facilitiesU.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in West Virginiaviolation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. The parties are awaiting a decision from the District Court, but there is no deadline for that decision. FirstEnergy is unable to predict the outcome or estimate the possible loss or range of loss.
National Ambient Air Quality Standards
The EPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but 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 decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO2emissions intwophases (2012 and 2014), ultimately capping SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions.On June 12, 2012, the EPA revised certain CSAPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, which MPNew York, Texas, 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 assetsWisconsin and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service)new unit set-asides in its Maryland, New Jersey,Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Pennsylvania franchise areas. Its results reflectTennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the commodity costsU.S. Court of securingAppeals for the District of Columbia Circuit pending a decision on legal challenges argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.
Hazardous Air Pollutant Emissions
On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generationgenerating units effective in April 2015 with averaging of emissions from FESmultiple units located at a single plant.
Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the deactivation by September 1, 2012 (subject to a reliability review by PJM) ofninecoal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and from non-affiliated power suppliers andWillow Island) with a total capacity of3,349MW (generating, on average, approximatelytenpercent of the deferral and amortization of certain fuel costs.
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The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived fromproduced by the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATHcompanies over the past three years) due to MATS and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operationenvironmental regulations.MATS has been challenged in the U.S. Court of a portionAppeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. FirstEnergy transmission system. Its results reflectand other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS.Depending on the netoutcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS is estimated to be$975 millionand other changes to FirstEnergy's operations may result.
On March 8, 2012, FGCO filed an application for a feasibility study with PJM to install and MISO transmission expenses relatedinterconnect to the deliverytransmission system832megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. However, when these units did not clear the May PJM capacity auction, the decision was made to not proceed with the project at this time. On April 25, 2012, PJM concluded its initial analysis of the respective generation loads. reliability impacts from our previously announced plant deactivations and requested RMR arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.On June 1, 2011,July 10, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. On July 16, 2012, FGCO and ATSI transmission assets previously dedicatedfiled an application with FERC for authorization to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.
The Competitive Energy Services segment, through FES, supplies electric powertransfer from FGCO to end-use customers through retail and wholesale arrangements, including associated company power sales to meet 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 inATSI 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 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 related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.
The Other/Corporate segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment.
Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.
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Segment Financial Information
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | | | | | | | | |
| | | Regulated | | | Energy | | | Independent | | | Other/ | | | Reconciling | | | | |
| Three Months Ended | | Distribution | | | Services | | | Transmission | | | Corporate | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
June 30, 2011 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,485 | | | $ | 1,495 | | | $ | 105 | | | $ | (30 | ) | | $ | (7 | ) | | $ | 4,048 | |
| Internal revenues | | | — | | | | 318 | | | | — | | | | — | | | | (306 | ) | | | 12 | |
| | | | | | | | | | | | | | | | | | | |
| Total revenues | | | 2,485 | | | | 1,813 | | | | 105 | | | | (30 | ) | | | (313 | ) | | | 4,060 | |
| Depreciation and amortization | | | 240 | | | | 107 | | | | 18 | | | | 7 | | | | — | | | | 372 | |
| Investment income (loss), net | | | 27 | | | | 15 | | | | — | | | | 1 | | | | (12 | ) | | | 31 | |
| Net interest charges | | | 145 | | | | 67 | | | | 11 | | | | 21 | | | | 1 | | | | 245 | |
| Income taxes | | | 108 | | | | 7 | | | | 18 | | | | (30 | ) | | | (2 | ) | | | 101 | |
| Net income (loss) | | | 184 | | | | 12 | | | | 31 | | | | (51 | ) | | | (5 | ) | | | 171 | |
| Total assets | | | 26,932 | | | | 17,146 | | | | 2,339 | | | | 1,179 | | | | — | | | | 47,596 | |
| Total goodwill | | | 5,551 | | | | 905 | | | | — | | | | — | | | | — | | | | 6,456 | |
| Property additions | | | 302 | | | | 197 | | | | 45 | | | | 25 | | | | — | | | | 569 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2010 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 2,314 | | | $ | 795 | | | $ | 59 | | | $ | (21 | ) | | $ | (8 | ) | | $ | 3,139 | |
| Internal revenues | | | 19 | | | | 539 | | | | — | | | | — | | | | (558 | ) | | | — | |
| | | | | | | | | | | | | | | | | | | |
| Total revenues | | | 2,333 | | | | 1,334 | | | | 59 | | | | (21 | ) | | | (566 | ) | | | 3,139 | |
| Depreciation and amortization | | | 264 | | | | 71 | | | | 13 | | | | 3 | | | | — | | | | 351 | |
| Investment income (loss), net | | | 28 | | | | 13 | | | | — | | | | — | | | | (10 | ) | | | 31 | |
| Net interest charges | | | 124 | | | | 33 | | | | 5 | | | | 9 | | | | (4 | ) | | | 167 | |
| Income taxes | | | 81 | | | | 75 | | | | 7 | | | | (12 | ) | | | (17 | ) | | | 134 | |
| Net income (loss) | | | 132 | | | | 121 | | | | 11 | | | | (20 | ) | | | 12 | | | | 256 | |
| Total assets | | | 21,457 | | | | 11,102 | | | | 993 | | | | 914 | | | | — | | | | 34,466 | |
| Total goodwill | | | 5,551 | | | | 24 | | | | — | | | | — | | | | — | | | | 5,575 | |
| Property additions | | | 157 | | | | 290 | | | | 15 | | | | 27 | | | | — | | | | 489 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Six Months Ended | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2011 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 4,753 | | | $ | 2,736 | | | $ | 172 | | | $ | (53 | ) | | $ | (16 | ) | | $ | 7,592 | |
| Internal revenues | | | — | | | | 661 | | | | — | | | | — | | | | (617 | ) | | | 44 | |
| | | | | | | | | | | | | | | | | | | |
| Total revenues | | | 4,753 | | | | 3,397 | | | | 172 | | | | (53 | ) | | | (633 | ) | | | 7,636 | |
| Depreciation and amortization | | | 485 | | | | 195 | | | | 31 | | | | 13 | | | | — | | | | 724 | |
| Investment income (loss), net | | | 52 | | | | 21 | | | | — | | | | 1 | | | | (22 | ) | | | 52 | |
| Net interest charges | | | 276 | | | | 122 | | | | 20 | | | | 40 | | | | — | | | | 458 | |
| Income taxes | | | 164 | | | | 10 | | | | 25 | | | | (50 | ) | | | 30 | | | | 179 | |
| Net income (loss) | | | 280 | | | | 17 | | | | 44 | | | | (86 | ) | | | (39 | ) | | | 216 | |
| Total assets | | | 26,932 | | | | 17,146 | | | | 2,339 | | | | 1,179 | | | | — | | | | 47,596 | |
| Total goodwill | | | 5,551 | | | | 905 | | | | — | | | | — | | | | — | | | | 6,456 | |
| Property additions | | | 479 | | | | 411 | | | | 72 | | | | 56 | | | | — | | | | 1,018 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
June 30, 2010 | | | | | | | | | | | | | | | | | | | | | | | | |
| External revenues | | $ | 4,798 | | | $ | 1,514 | | | $ | 116 | | | $ | (43 | ) | | $ | (14 | ) | | $ | 6,371 | |
| Internal revenues | | | 19 | | | | 1,213 | | | | — | | | | — | | | | (1,165 | ) | | | 67 | |
| | | | | | | | | | | | | | | | | | | |
| Total revenues | | | 4,817 | | | | 2,727 | | | | 116 | | | | (43 | ) | | | (1,179 | ) | | | 6,438 | |
| Depreciation and amortization | | | 577 | | | | 148 | | | | 25 | | | | 6 | | | | — | | | | 756 | |
| Investment income (loss), net | | | 54 | | | | 14 | | | | — | | | | 1 | | | | (22 | ) | | | 47 | |
| Net interest charges | | | 248 | | | | 66 | | | | 10 | | | | 22 | | | | (7 | ) | | | 339 | |
| Income taxes | | | 143 | | | | 117 | | | | 14 | | | | (24 | ) | | | (5 | ) | | | 245 | |
| Net income (loss) | | | 235 | | | | 190 | | | | 23 | | | | (39 | ) | | | (4 | ) | | | 405 | |
| Total assets | | | 21,457 | | | | 11,102 | | | | 993 | | | | 914 | | | | — | | | | 34,466 | |
| Total goodwill | | | 5,551 | | | | 24 | | | | — | | | | — | | | | — | | | | 5,575 | |
| Property additions | | | 309 | | | | 619 | | | | 29 | | | | 40 | | | | — | | | | 997 | |
Reconciling adjustments primarily consist of elimination of intersegment transactions.
14. IMPAIRMENT OF LONG-LIVED ASSETS
FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. The following events described in the sections below occurred during for the first six months of 2011 that indicated the carrying value of certain assets may not be recoverable.
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Fremont Energy Center
On March 11, 2011, FirstEnergy and American Municipal Power, Inc., 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 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 indicatedEastlake Units 1-5 and Lakeshore Unit 18 for conversion to synchronous condensers by ATSI for transmission reliability purposes as directed by PJM. Upon FERC approval, it is expected that the carrying cost ofassets will be transferred in staggered closings when 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 July 28, 2011, FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.
Peaking Facilities
units are no longer needed for RMR purposes. During the first six months of 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. FirstEnergy recorded impairment charges of $7 million and $21 million during the three months and six months ended June 30, 2011,2012, FirstEnergy recognized pre-tax severance expense of approximately$10 million($6 million by FES) and $17 million ($10 million by FES), respectively, as a result of the recoverability evaluation.deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.
15. ASSET RETIREMENT OBLIGATIONSOn March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, in June 2009. 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 and report GHG emissions commencing in 2010. 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 NSR preconstruction permits would be required including an emissions applicability threshold of75,000tons per year of CO2equivalents for existing facilities under the CAA's PSD program.
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 that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To 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. A December 2011 U.N. Climate Change Conference in Durban, South Africa, established a negotiating process to develop a new
post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions 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-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has recognized applicable legal obligationstaken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for AROsminimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. In July 2012, the period for finalizing the Section 316(b) regulation was extendedto July 27, 2013.FirstEnergy is studying various control options and their associated costcosts and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system. Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA and the Migratory Bird Treaty Act for nuclear power plant decommissioning, reclamationthree petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007.On June 5, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of sludgelimitations for civil liability claims for those petroleum spills toJanuary 31, 2013. FGCO does not anticipate any losses resulting from this matter to be material.
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 coal-fired Hatfield's Ferry Plant. These criteria are reflected in the NPDES water discharge permit issued by PA DEP for that project. In January 2009, AE Supply appealed the PA DEP's permitting decision to the EHB, due to estimated costs in excess of$150 million in order to install technology to meet TDS and sulfate limits in the NPDES permit. Environmental Integrity Project and Citizens Coal Council also appealed the NPDES permit seeking to impose more stringent technology-based effluent limitations.In April 2012, a joint motion was filed by the parties informing the EHB of a proposed settlement and seeking the lifting of a portion of the EHB's stay of certain terms of the Hatfield's Ferry Plant's NPDES permit. The joint motion was granted by the EHB on April 27, 2012.The proposed settlement, in the form of a Consent Decree, was lodged with the Commonwealth Court of Pennsylvania and published in the June 23, 2012, Pennsylvania Bulletin for a 30-day public comment period. The Consent Decree, if entered by the Commonwealth Court of Pennsylvania, will resolve the disputes concerning the Hatfield's Ferry Plant NPDES permit, including TDS and sulphate limits.
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 would apply only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP's recommended sulfate impairment designation. PA DEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.
In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin Plant, which imposes TDS, sulfate
concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP has appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require 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, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit in the U.S. District Court for the Northern District of West Virginia alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a 60-day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant. MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. In April 2012, the parties reached a settlement to resolve these CWA citizen suit claims for an immaterial amount. If approved by the Court, a Consent Decree will be entered by the Court to resolve these claims. MP is currently seeking relief from the arsenic limits through WVDEP agency review.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal ponds and closurerequirements pending the EPA's evaluation of the need for future regulation.
In December 2009, in an advance notice of public rulemaking, the EPA asserted that the large volumes of coal ashcombustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions 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 sites. In addition, of coal combustion residuals.On July 27, 2012, the PA DEP filed a complaint against FGCO in the U.S. District Court for the Western District of Pennsylvania with claims under the Resource Conservation and Recovery Act and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FGCO to resolve those claims. The Consent Decree will be published to allow for a 30-day public comment period and requires FGCO to conduct monitoring, studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. BMP is pursuing several options for disposal of CCB following December 31, 2016.
FirstEnergy's future cost of compliance with any coal combustion residuals regulations that 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
Certain of our utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. 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 ofJune 30, 2012, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$122 million(including$86 millionapplicable to JCP&L) have been accrued throughJune 30, 2012. Included in the total are accrued liabilities of approximately$79 millionfor 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.FirstEnergy has recognized conditional asset retirement obligations (primarilyor its subsidiaries could be found potentially responsible for asbestos remediation).additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.
OTHER LEGAL PROCEEDINGS
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofJune 30, 2012, FirstEnergy had approximately$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2.As required by the NRC, FirstEnergy annually
recalculates and adjusts the amount of its parental guarantee, as appropriate. The ARO liabilities for FES, OEvalues of FirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy's obligation to fund the trusts may increase. Disruptions in the capital markets and TE primarily relate totheir effects on particular businesses and the economy could also affect the values of the NDT. FirstEnergy Corp. currently maintains a $95 millionparental guaranty in support of the decommissioning of nuclear facilities.
In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. The NRC subsequently narrowed the scope of admitted contentions in this proceeding to a challenge to the computer code used to model source terms in FENOC's Severe Accident Mitigation Alternatives analysis. On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.The intervenors supplemented their petition for a contention on the shield building on multiple occasions. On July 9, 2012, the intervenors petitioned the ASLB for a new contention on the environmental impacts of temporary spent fuel storage at Davis-Besse due to the lack of a repository and the disposal of these wastes. The ASLB has yet to rule on the admission of these latest requests for new contentions.
Similarly, on June 18 and 19, 2012, the intervenors in the Davis-Besse license renewal proceeding and other petitioners requested that the NRC suspends the issuance of final decisions in all pending reactor licensing proceedings as a result of the decision in the case of State of New York v. NRC, No. 11-1045. (D.C. Cir. June 8, 2012). In this case, the D.C. Circuit vacated the NRC's updated Waste Confidence Decision and its Temporary Storage Rule and remanded those rulemakings to the NRC for further consideration. FENOC and other Licensees opposed the suspension request. By order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the D.C. Circuit decision and all pending contentions on this topic should be held in abeyance until further order. The NRC also directed that all licensing reviews and proceedings should continue to move forward.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC, including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.On June 21, 2012, the NRC issued an Inspection Report that concluded that FENOC established a sufficient basis for the causes of the shield building laminar cracking.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence. Additional adverse findings by the NRC could result in further inspection activities.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.
On February 16, 2012, the NRC issued a request for information to the licensed operators of11nuclear power plants, including Beaver Valley Davis-BessePower Station Units 1 and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2, and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relatewith respect to the decommissioningmodeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in higher burn up fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer and
that the NRC might consider imposing restrictions on reactor operating limits.On March 16, 2012, FENOC submitted its response to the NRC demonstrating that the NRC requirements are being met. FENOC also agreed to submit to the NRC revised large break loss of coolant accident analyses by December 15, 2016, that further consider the effects of fuel pellet thermal conductivity degradation.
ICG Litigation
On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and Anker Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. 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 from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for$104 million($90 millionin future damages and$14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal.Briefing on the Appeal has concluded and an oral argument was held on May 16, 2012. A decision from the Appellate court is expected in the fourth quarter of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.
Other Legal Matters
In February 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 had been approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction. The court granted the motion to dismiss and the plaintiffs appealed the decision to the Court of Appeals of Ohio. The Court of Appeals affirmed the dismissal of the TMI-2 nuclear generating facility. FES, OE, JCP&L, Met-Ed and Penelec useComplaint by the Court of Common Pleas on all counts except for one relating to an expected cash flow approach to measure the fair valueallegation of their nuclear decommissioning ARO.
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 revisionfraud which it remanded to the estimated cash flows associatedtrial court. The Companies timely filed a notice of appeal with the ARO liabilitiesSupreme Court of FESOhio on December 5, 2011, challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio agreed to hear the appeal.
There are various lawsuits, claims (including claims for asbestos exposure) and OEproceedings related to FirstEnergy's normal business operations pending against FirstEnergy and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively.
During the second quarter of 2011, studies were completed to update the estimated cost of decommissioning the Davis-Besse nuclear facility.its subsidiaries. The cost studies resulted in a revisionother potentially material items not otherwise discussed above are described under Note 8, Regulatory Matters to the estimated cash flows associated withCombined Notes to the AROConsolidated Financial Statements.
FirstEnergy accrues legal liabilities of FESonly when it concludes that it is probable that it has an obligation for such costs and reduced the liability for FES incan reasonably estimate the amount of $5 million.
The revisionssuch costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to the estimated cash flows had no significant impactliability based on accretionany of the obligation during the three monthsmatters referenced above, it could have a material adverse effect on FirstEnergy's or its subsidiaries' financial condition, results of operations and six months ended June 30, 2011 when compared to the same periods of 2010.cash flows.
16.10. SUPPLEMENTAL GUARANTOR INFORMATION
In 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’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’s undivided interest in Unit 1, rights and interests under the applicable lease and rights and interests under other related agreements, including 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 statementsCondensed Consolidating Statements of income for the three monthIncome and six month periods ended June 30, 2011 and 2010, consolidating balance sheets as of June 30, 2011 and December 31, 2010 and consolidating statements of cash flowsComprehensive Income for the three months and six months ended June 30, 20112012 and 20102011, Consolidating Balance Sheets as of June 30, 2012 and December 31, 2011, and Consolidating Statements of Cash Flows for the six months ended June 30, 2012 and 2011, for FES (parent and guarantor), FGCO and NGC (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FGCO and NGC are, therefore, reflected in FES’ investment accounts and earnings as if operating lease treatment was achieved. The principal elimination entries eliminate investments in subsidiaries and intercompany balances and transactions and the entries required to reflect operating lease treatment associated with the 2007 Bruce Mansfield Unit 1 sale and leaseback transaction.
75
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited) AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | |
REVENUES | | $ | 1,275 | | | $ | 535 | | | $ | 393 | | | $ | (911 | ) | | $ | 1,292 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 6 | | | | 266 | | | | 44 | | | | — | | | | 316 | |
| Purchased power from affiliates | | | 902 | | | | 9 | | | | 65 | | | | (911 | ) | | | 65 | |
| Purchased power from non-affiliates | | | 332 | | | | (3 | ) | | | — | | | | — | | | | 329 | |
| Other operating expenses | | | 159 | | | | 115 | | | | 143 | | | | 12 | | | | 429 | |
| Provision for depreciation | | | 1 | | | | 32 | | | | 36 | | | | (1 | ) | | | 68 | |
| General taxes | | | 16 | | | | 8 | | | | 6 | | | | — | | | | 30 | |
| Impairment of long-lived assets | | | — | | | | 7 | | | | — | | | | — | | | | 7 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 1,416 | | | | 434 | | | | 294 | | | | (900 | ) | | | 1,244 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (141 | ) | | | 101 | | | | 99 | | | | (11 | ) | | | 48 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | — | | | | 1 | | | | 15 | | | | — | | | | 16 | |
| Miscellaneous income (expense), including net income from equity investees | | | 123 | | | | 1 | | | | — | | | | (120 | ) | | | 4 | |
| Interest expense — affiliates | | | — | | | | (1 | ) | | | (1 | ) | | | — | | | | (2 | ) |
| Interest expense — other | | | (24 | ) | | | (28 | ) | | | (16 | ) | | | 16 | | | | (52 | ) |
| Capitalized interest | | | — | | | | 5 | | | | 5 | | | | — | | | | 10 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 99 | | | | (22 | ) | | | 3 | | | | (104 | ) | | | (24 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | | (42 | ) | | | 79 | | | | 102 | | | | (115 | ) | | | 24 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (62 | ) | | | 25 | | | | 38 | | | | 3 | | | | 4 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 20 | | | $ | 54 | | | $ | 64 | | | $ | (118 | ) | | $ | 20 | |
| | | | | | | | | | | | | | | | |
76
|
| | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, 2012 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 1,430 |
| | $ | 636 |
| | $ | 473 |
| | $ | (1,083 | ) | | $ | 1,456 |
|
OPERATING EXPENSES: | | | | | | | | | | |
| Fuel | | — |
| | 336 |
| | 44 |
| | — |
| | 380 |
|
| Purchased power from affiliates | | 1,156 |
| | — |
| | 60 |
| | (1,083 | ) | | 133 |
|
| Purchased power from non-affiliates | | 434 |
| | — |
| | — |
| | — |
| | 434 |
|
| Other operating expenses | | 107 |
| | 100 |
| | 172 |
| | 14 |
| | 393 |
|
| Provision for depreciation | | 1 |
| | 30 |
| | 39 |
| | (1 | ) | | 69 |
|
| General taxes | | 20 |
| | 8 |
| | 4 |
| | — |
| | 32 |
|
| Total operating expenses | | 1,718 |
| | 474 |
| | 319 |
| | (1,070 | ) | | 1,441 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (288 | ) | | 162 |
| | 154 |
| | (13 | ) | | 15 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | |
| Investment income | | — |
| | 5 |
| | 7 |
| | (6 | ) | | 6 |
|
| Miscellaneous income, including net income from equity investees | | 279 |
| | 19 |
| | — |
| | (278 | ) | | 20 |
|
| Interest expense — affiliates | | (5 | ) | | (2 | ) | | (1 | ) | | 6 |
| | (2 | ) |
| Interest expense — other | | (24 | ) | | (26 | ) | | (14 | ) | | 16 |
| | (48 | ) |
| Capitalized interest | | — |
| | 1 |
| | 8 |
| | — |
| | 9 |
|
| Total other income (expense) | | 250 |
| | (3 | ) | | — |
| | (262 | ) | | (15 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (38 | ) | | 159 |
| | 154 |
| | (275 | ) | | — |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (37 | ) | | (7 | ) | | 42 |
| | 3 |
| | 1 |
|
| | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (1 | ) | | $ | 166 |
| | $ | 112 |
| | $ | (278 | ) | | $ | (1 | ) |
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME (LOSS) | | $ | (1 | ) | | $ | 166 |
| | $ | 112 |
| | $ | (278 | ) | | $ | (1 | ) |
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | | | | | | | | | | |
| Pensions and OPEB prior service costs | | 8 |
| | 7 |
| | — |
| | (7 | ) | | 8 |
|
| Amortized gain on derivative hedges | | 1 |
| | — |
| | — |
| | — |
| | 1 |
|
| Change in unrealized gain on available for sale securities | | 3 |
| | — |
| | 3 |
| | (3 | ) | | 3 |
|
| Other comprehensive income | | 12 |
| | 7 |
| | 3 |
| | (10 | ) | | 12 |
|
| Income taxes on other comprehensive income | | 2 |
| | 3 |
| | 1 |
| | (4 | ) | | 2 |
|
| Other comprehensive income, net of tax | | 10 |
| | 4 |
| | 2 |
| | (6 | ) | | 10 |
|
COMPREHENSIVE INCOME | | $ | 9 |
| | $ | 170 |
| | $ | 114 |
| | $ | (284 | ) | | $ | 9 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited) AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | |
REVENUES | | $ | 2,642 | | | $ | 1,278 | | | $ | 862 | | | $ | (2,098 | ) | | $ | 2,684 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 7 | | | | 560 | | | | 92 | | | | — | | | | 659 | |
| Purchased power from affiliates | | | 2,087 | | | | 11 | | | | 134 | | | | (2,098 | ) | | | 134 | |
| Purchased power from non-affiliates | | | 629 | | | | (3 | ) | | | — | | | | — | | | | 626 | |
| Other operating expenses | | | 321 | | | | 233 | | | | 331 | | | | 25 | | | | 910 | |
| Provision for depreciation | | | 2 | | | | 63 | | | | 74 | | | | (3 | ) | | | 136 | |
| General taxes | | | 27 | | | | 19 | | | | 14 | | | | — | | | | 60 | |
| Impairment charges of long-lived assets | | | — | | | | 20 | | | | — | | | | — | | | | 20 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 3,073 | | | | 903 | | | | 645 | | | | (2,076 | ) | | | 2,545 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (431 | ) | | | 375 | | | | 217 | | | | (22 | ) | | | 139 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 1 | | | | 1 | | | | 20 | | | | — | | | | 22 | |
| Miscellaneous income, including net income from equity investees | | | 356 | | | | 2 | | | | — | | | | (350 | ) | | | 8 | |
| Interest expense — affiliates | | | (1 | ) | | | (1 | ) | | | (1 | ) | | | — | | | | (3 | ) |
| Interest expense — other | | | (48 | ) | | | (56 | ) | | | (33 | ) | | | 32 | | | | (105 | ) |
| Capitalized interest | | | — | | | | 10 | | | | 10 | | | | — | | | | 20 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 308 | | | | (44 | ) | | | (4 | ) | | | (318 | ) | | | (58 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME (LOSS) BEFORE INCOME TAXES | | | (123 | ) | | | 331 | | | | 213 | | | | (340 | ) | | | 81 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (179 | ) | | | 119 | | | | 80 | | | | 5 | | | | 25 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 56 | | | $ | 212 | | | $ | 133 | | | $ | (345 | ) | | $ | 56 | |
| | | | | | | | | | | | | | | | |
77
|
| | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2012 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 2,920 |
| | $ | 1,178 |
| | $ | 867 |
| | $ | (1,993 | ) | | $ | 2,972 |
|
OPERATING EXPENSES: | | | | | | | | | | |
| Fuel | | — |
| | 576 |
| | 99 |
| | — |
| | 675 |
|
| Purchased power from affiliates | | 2,121 |
| | — |
| | 122 |
| | (1,993 | ) | | 250 |
|
| Purchased power from non-affiliates | | 921 |
| | — |
| | — |
| | — |
| | 921 |
|
| Other operating expenses | | 183 |
| | 192 |
| | 288 |
| | 25 |
| | 688 |
|
| Provision for depreciation | | 2 |
| | 60 |
| | 73 |
| | (3 | ) | | 132 |
|
| General taxes | | 40 |
| | 18 |
| | 11 |
| | — |
| | 69 |
|
| Total operating expenses | | 3,267 |
| | 846 |
| | 593 |
| | (1,971 | ) | | 2,735 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (347 | ) | | 332 |
| | 274 |
| | (22 | ) | | 237 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | |
| Investment income | | 1 |
| | 9 |
| | 12 |
| | (10 | ) | | 12 |
|
| Miscellaneous income, including net income from equity investees | | 537 |
| | 19 |
| | — |
| | (532 | ) | | 24 |
|
| Interest expense — affiliates | | (9 | ) | | (3 | ) | | (2 | ) | | 10 |
| | (4 | ) |
| Interest expense — other | | (47 | ) | | (52 | ) | | (21 | ) | | 31 |
| | (89 | ) |
| Capitalized interest | | — |
| | 2 |
| | 16 |
| | — |
| | 18 |
|
| Total other income (expense) | | 482 |
| | (25 | ) | | 5 |
| | (501 | ) | | (39 | ) |
| | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 135 |
| | 307 |
| | 279 |
| | (523 | ) | | 198 |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | 14 |
| | (8 | ) | | 65 |
| | 6 |
| | 77 |
|
| | | | | | | | | | | |
| NET INCOME | | $ | 121 |
| | $ | 315 |
| | $ | 214 |
| | $ | (529 | ) | | $ | 121 |
|
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME | | $ | 121 |
| | $ | 315 |
| | $ | 214 |
| | $ | (529 | ) | | $ | 121 |
|
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME | | | | | | | | | | |
| Pensions and OPEB prior service costs | | 3 |
| | 3 |
| | — |
| | (3 | ) | | 3 |
|
| Amortized loss on derivative hedges | | (4 | ) | | — |
| | — |
| | — |
| | (4 | ) |
| Change in unrealized gain on available for sale securities | | 13 |
| | — |
| | 13 |
| | (13 | ) | | 13 |
|
| Other comprehensive income | | 12 |
| | 3 |
| | 13 |
| | (16 | ) | | 12 |
|
| Income taxes on other comprehensive income | | 4 |
| | 1 |
| | 5 |
| | (6 | ) | | 4 |
|
| Other comprehensive income, net of tax | | 8 |
| | 2 |
| | 8 |
| | (10 | ) | | 8 |
|
COMPREHENSIVE INCOME | | $ | 129 |
| | $ | 317 |
| | $ | 222 |
| | $ | (539 | ) | | $ | 129 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited) AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | |
REVENUES | | $ | 1,307 | | | $ | 581 | | | $ | 339 | | | $ | (901 | ) | | $ | 1,326 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 7 | | | | 302 | | | | 34 | | | | — | | | | 343 | |
| Purchased power from affiliates | | | 913 | | | | 8 | | | | 49 | | | | (901 | ) | | | 69 | |
| Purchased power from non-affiliates | | | 310 | | | | — | | | | — | | | | — | | | | 310 | |
| Other operating expenses | | | 81 | | | | 94 | | | | 117 | | | | 12 | | | | 304 | |
| Provision for depreciation | | | 1 | | | | 27 | | | | 36 | | | | (1 | ) | | | 63 | |
| General taxes | | | 6 | | | | 9 | | | | 7 | | | | — | | | | 22 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 1,318 | | | | 440 | | | | 243 | | | | (890 | ) | | | 1,111 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (11 | ) | | | 141 | | | | 96 | | | | (11 | ) | | | 215 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 2 | | | | — | | | | 11 | | | | — | | | | 13 | |
| Miscellaneous income, including net income from equity investees | | | 151 | | | | 1 | | | | — | | | | (148 | ) | | | 4 | |
| Interest expense — affiliates | | | — | | | | (2 | ) | | | — | | | | — | | | | (2 | ) |
| Interest expense — other | | | (24 | ) | | | (28 | ) | | | (15 | ) | | | 16 | | | | (51 | ) |
| Capitalized interest | | | — | | | | 20 | | | | 4 | | | | — | | | | 24 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 129 | | | | (9 | ) | | | — | | | | (132 | ) | | | (12 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 118 | | | | 132 | | | | 96 | | | | (143 | ) | | | 203 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (16 | ) | | | 48 | | | | 34 | | | | 3 | | | | 69 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 134 | | | $ | 84 | | | $ | 62 | | | $ | (146 | ) | | $ | 134 | |
| | | | | | | | | | | | | | | | |
78
|
| | | | | | | | | | | | | | | | | | | | |
| For the Three Months Ended June 30, 2011 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 1,275 |
| | $ | 535 |
| | $ | 393 |
| | $ | (911 | ) | | $ | 1,292 |
|
OPERATING EXPENSES: | | | | | | | | | | |
| Fuel | | 6 |
| | 266 |
| | 44 |
| | — |
| | 316 |
|
| Purchased power from affiliates | | 902 |
| | 9 |
| | 65 |
| | (911 | ) | | 65 |
|
| Purchased power from non-affiliates | | 332 |
| | (3 | ) | | — |
| | — |
| | 329 |
|
| Other operating expenses | | 159 |
| | 108 |
| | 134 |
| | 12 |
| | 413 |
|
| Provision for depreciation | | 1 |
| | 32 |
| | 37 |
| | (1 | ) | | 69 |
|
| General taxes | | 16 |
| | 8 |
| | 6 |
| | — |
| | 30 |
|
| Impairment of long-lived assets | | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Total operating expenses | | 1,416 |
| | 427 |
| | 286 |
| | (900 | ) | | 1,229 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (141 | ) | | 108 |
| | 107 |
| | (11 | ) | | 63 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | |
| Investment income | | — |
| | 1 |
| | 15 |
| | — |
| | 16 |
|
| Miscellaneous income, including net income from equity investees | | 132 |
| | 1 |
| | — |
| | (129 | ) | | 4 |
|
| Interest expense — affiliates | | — |
| | (1 | ) | | (1 | ) | | — |
| | (2 | ) |
| Interest expense — other | | (24 | ) | | (28 | ) | | (16 | ) | | 16 |
| | (52 | ) |
| Capitalized interest | | — |
| | 5 |
| | 5 |
| | — |
| | 10 |
|
| Total other income (expense) | | 108 |
| | (22 | ) | | 3 |
| | (113 | ) | | (24 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (33 | ) | | 86 |
| | 110 |
| | (124 | ) | | 39 |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (62 | ) | | 28 |
| | 41 |
| | 3 |
| | 10 |
|
| | | | | | | | | | | |
| NET INCOME | | $ | 29 |
| | $ | 58 |
| | $ | 69 |
| | $ | (127 | ) | | $ | 29 |
|
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME | | $ | 29 |
| | $ | 58 |
| | $ | 69 |
| | $ | (127 | ) | | $ | 29 |
|
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | |
| Pensions and OPEB prior service costs | | (5 | ) | | (4 | ) | | — |
| | 4 |
| | (5 | ) |
| Amortized gain on derivative hedges | | 14 |
| | — |
| | — |
| | — |
| | 14 |
|
| Change in unrealized gain on available for sale securities | | 8 |
| | — |
| | 8 |
| | (8 | ) | | 8 |
|
| Other comprehensive income (loss) | | 17 |
| | (4 | ) | | 8 |
| | (4 | ) | | 17 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | 8 |
| | (2 | ) | | 3 |
| | (1 | ) | | 8 |
|
| Other comprehensive income (loss), net of tax | | 9 |
| | (2 | ) | | 5 |
| | (3 | ) | | 9 |
|
COMPREHENSIVE INCOME | | $ | 38 |
| | $ | 56 |
| | $ | 74 |
| | $ | (130 | ) | | $ | 38 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited) AND COMPREHENSIVE INCOME
| | | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
| |
REVENUES | | $ | 2,674 | | | $ | 1,149 | | | $ | 765 | | | $ | (1,874 | ) | | $ | 2,714 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
EXPENSES: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 12 | | | | 582 | | | | 77 | | | | — | | | | 671 | |
| Purchased power from affiliates | | | 1,881 | | | | 12 | | | | 111 | | | | (1,874 | ) | | | 130 | |
| Purchased power from non-affiliates | | | 760 | | | | — | | | | — | | | | — | | | | 760 | |
| Other operating expenses | | | 134 | | | | 194 | | | | 256 | | | | 24 | | | | 608 | |
| Provision for depreciation | | | 2 | | | | 54 | | | | 73 | | | | (3 | ) | | | 126 | |
| General taxes | | | 11 | | | | 24 | | | | 14 | | | | — | | | | 49 | |
| Impairment of long-lived assets | | | — | | | | 2 | | | | — | | | | — | | | | 2 | |
| | | | | | | | | | | | | | | | |
| Total expenses | | | 2,800 | | | | 868 | | | | 531 | | | | (1,853 | ) | | | 2,346 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OPERATING INCOME (LOSS) | | | (126 | ) | | | 281 | | | | 234 | | | | (21 | ) | | | 368 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 4 | | | | — | | | | 10 | | | | — | | | | 14 | |
| Miscellaneous income, including net income from equity investees | | | 317 | | | | 1 | | | | — | | | | (311 | ) | | | 7 | |
| Interest expense to affiliates | | | — | | | | (4 | ) | | | (1 | ) | | | — | | | | (5 | ) |
| Interest expense — other | | | (48 | ) | | | (54 | ) | | | (31 | ) | | | 32 | | | | (101 | ) |
| Capitalized interest | | | — | | | | 36 | | | | 8 | | | | — | | | | 44 | |
| | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 273 | | | | (21 | ) | | | (14 | ) | | | (279 | ) | | | (41 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME BEFORE INCOME TAXES | | | 147 | | | | 260 | | | | 220 | | | | (300 | ) | | | 327 | |
| | | | | | | | | | | | | | | | | | | | | |
INCOME TAXES (BENEFITS) | | | (67 | ) | | | 97 | | | | 78 | | | | 5 | | | | 113 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NET INCOME | | $ | 214 | | | $ | 163 | | | $ | 142 | | | $ | (305 | ) | | $ | 214 | |
| | | | | | | | | | | | | | | | |
79
|
| | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2011 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| STATEMENTS OF INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| REVENUES | | $ | 2,642 |
| | $ | 1,278 |
| | $ | 862 |
| | $ | (2,098 | ) | | $ | 2,684 |
|
OPERATING EXPENSES: | | | | | | | | | | |
| Fuel | | 7 |
| | 560 |
| | 92 |
| | — |
| | 659 |
|
| Purchased power from affiliates | | 2,087 |
| | 11 |
| | 134 |
| | (2,098 | ) | | 134 |
|
| Purchased power from non-affiliates | | 629 |
| | (3 | ) | | — |
| | — |
| | 626 |
|
| Other operating expenses | | 321 |
| | 219 |
| | 313 |
| | 25 |
| | 878 |
|
| Provision for depreciation | | 2 |
| | 63 |
| | 76 |
| | (3 | ) | | 138 |
|
| General taxes | | 27 |
| | 19 |
| | 14 |
| | — |
| | 60 |
|
| Impairment of long-lived assets | | — |
| | 20 |
| | — |
| | — |
| | 20 |
|
| Total operating expenses | | 3,073 |
| | 889 |
| | 629 |
| | (2,076 | ) | | 2,515 |
|
| | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (431 | ) | | 389 |
| | 233 |
| | (22 | ) | | 169 |
|
| | | | | | | | | | | |
| OTHER INCOME (EXPENSE): | | | | | | | | | | |
| Investment income | | 1 |
| | 1 |
| | 20 |
| | — |
| | 22 |
|
| Miscellaneous income, including net income from equity investees | | 374 |
| | 2 |
| | — |
| | (368 | ) | | 8 |
|
| Interest expense — affiliates | | (1 | ) | | (1 | ) | | (1 | ) | | — |
| | (3 | ) |
| Interest expense — other | | (48 | ) | | (56 | ) | | (33 | ) | | 32 |
| | (105 | ) |
| Capitalized interest | | — |
| | 10 |
| | 10 |
| | — |
| | 20 |
|
| Total other income (expense) | | 326 |
| | (44 | ) | | (4 | ) | | (336 | ) | | (58 | ) |
| | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (105 | ) | | 345 |
| | 229 |
| | (358 | ) | | 111 |
|
| | | | | | | | | | | |
| INCOME TAXES (BENEFITS) | | (179 | ) | | 125 |
| | 86 |
| | 5 |
| | 37 |
|
| | | | | | | | | | | |
| NET INCOME | | $ | 74 |
| | $ | 220 |
| | $ | 143 |
| | $ | (363 | ) | | $ | 74 |
|
| | | | | | | | | | | |
| STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | |
| | | | | | | | | | | |
| NET INCOME | | $ | 74 |
| | $ | 220 |
| | $ | 143 |
| | $ | (363 | ) | | $ | 74 |
|
| | | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | |
| Pensions and OPEB prior service costs | | (9 | ) | | (8 | ) | | — |
| | 8 |
| | (9 | ) |
| Amortized gain on derivative hedges | | 5 |
| | — |
| | — |
| | — |
| | 5 |
|
| Change in unrealized gain on available for sale securities | | 15 |
| | — |
| | 15 |
| | (15 | ) | | 15 |
|
| Other comprehensive income (loss) | | 11 |
| | (8 | ) | | 15 |
| | (7 | ) | | 11 |
|
| Income taxes (benefits) on other comprehensive income (loss) | | 4 |
| | (4 | ) | | 6 |
| | (2 | ) | | 4 |
|
| Other comprehensive income (loss), net of tax | | 7 |
| | (4 | ) | | 9 |
| | (5 | ) | | 7 |
|
COMPREHENSIVE INCOME | | $ | 81 |
| | $ | 216 |
| | $ | 152 |
| | $ | (368 | ) | | $ | 81 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
ASSETS | | | | | | | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 450 | | | | — | | | | — | | | | — | | | | 450 | |
| Associated companies | | | 481 | | | | 425 | | | | 263 | | | | (679 | ) | | | 490 | |
| Other | | | 24 | | | | 23 | | | | 4 | | | | — | | | | 51 | |
| Notes receivable from associated companies | | | 6 | | | | 410 | | | | 74 | | | | — | | | | 490 | |
| Materials and supplies, at average cost | | | 54 | | | | 253 | | | | 192 | | | | — | | | | 499 | |
| Derivatives | | | 221 | | | | — | | | | — | | | | — | | | | 221 | |
| Prepayments and other | | | 34 | | | | 14 | | | | 1 | | | | — | | | | 49 | |
| | | | | | | | | | | | | | | | |
| | | | 1,270 | | | | 1,131 | | | | 534 | | | | (679 | ) | | | 2,256 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 101 | | | | 6,105 | | | | 5,634 | | | | (385 | ) | | | 11,455 | |
| Less — Accumulated provision for depreciation | | | 19 | | | | 2,067 | | | | 2,298 | | | | (178 | ) | | | 4,206 | |
| | | | | | | | | | | | | | | | |
| | | | 82 | | | | 4,038 | | | | 3,336 | | | | (207 | ) | | | 7,249 | |
| Construction work in progress | | | 10 | | | | 198 | | | | 486 | | | | — | | | | 694 | |
| Property, plant and equipment held for sale, net | | | — | | | | 487 | | | | — | | | | — | | | | 487 | |
| | | | | | | | | | | | | | | | |
| | | | 92 | | | | 4,723 | | | | 3,822 | | | | (207 | ) | | | 8,430 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | — | | | | — | | | | 1,184 | | | | — | | | | 1,184 | |
| Investment in associated companies | | | 5,302 | | | | — | | | | — | | | | (5,302 | ) | | | — | |
| Other | | | 1 | | | | 9 | | | | — | | | | — | | | | 10 | |
| | | | | | | | | | | | | | | | |
| | | | 5,303 | | | | 9 | | | | 1,184 | | | | (5,302 | ) | | | 1,194 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income tax benefits | | | 18 | | | | 344 | | | | — | | | | (362 | ) | | | — | |
| Customer intangibles | | | 129 | | | | — | | | | — | | | | — | | | | 129 | |
| Goodwill | | | 24 | | | | — | | | | — | | | | — | | | | 24 | |
| Property taxes | | | — | | | | 16 | | | | 25 | | | | — | | | | 41 | |
| Unamortized sale and leaseback costs | | | — | | | | 6 | | | | — | | | | 70 | | | | 76 | |
| Derivatives | | | 135 | | | | — | | | | — | | | | — | | | | 135 | |
| Other | | | 39 | | | | 97 | | | | 7 | | | | (68 | ) | | | 75 | |
| | | | | | | | | | | | | | | | |
| | | | 345 | | | | 463 | | | | 32 | | | | (360 | ) | | | 480 | |
| | | | | | | | | | | | | | | | |
| | | $ | 7,010 | | | $ | 6,326 | | | $ | 5,572 | | | $ | (6,548 | ) | | $ | 12,360 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 1 | | | $ | 436 | | | $ | 671 | | | $ | (20 | ) | | $ | 1,088 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 453 | | | | 88 | | | | — | | | | — | | | | 541 | |
| Other | | | — | | | | 1 | | | | — | | | | — | | | | 1 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 665 | | | | 231 | | | | 165 | | | | (668 | ) | | | 393 | |
| Other | | | 80 | | | | 111 | | | | — | | | | — | | | | 191 | |
| Derivatives | | | 242 | | | | — | | | | — | | | | — | | | | 242 | |
| Other | | | 69 | | | | 137 | | | | 46 | | | | 10 | | | | 262 | |
| | | | | | | | | | | | | | | | |
| | | | 1,510 | | | | 1,004 | | | | 882 | | | | (678 | ) | | | 2,718 | |
| | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Total equity | | | 3,858 | | | | 2,728 | | | | 2,556 | | | | (5,285 | ) | | | 3,857 | |
| Long-term debt and other long-term obligations | | | 1,483 | | | | 2,050 | | | | 706 | | | | (1,239 | ) | | | 3,000 | |
| | | | | | | | | | | | | | | | |
| | | | 5,341 | | | | 4,778 | | | | 3,262 | | | | (6,524 | ) | | | 6,857 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | — | | | | — | | | | — | | | | 942 | | | | 942 | |
| Accumulated deferred income taxes | | | — | | | | — | | | | 504 | | | | (288 | ) | | | 216 | |
| Asset retirement obligations | | | — | | | | 28 | | | | 847 | | | | — | | | | 875 | |
| Retirement benefits | | | 50 | | | | 245 | | | | — | | | | — | | | | 295 | |
| Lease market valuation liability | | | — | | | | 194 | | | | — | | | | — | | | | 194 | |
| Derivatives | | | 85 | | | | — | | | | — | | | | — | | | | 85 | |
| Other | | | 24 | | | | 77 | | | | 77 | | | | — | | | | 178 | |
| | | | | | | | | | | | | | | | |
| | | | 159 | | | | 544 | | | | 1,428 | | | | 654 | | | | 2,785 | |
| | | | | | | | | | | | | | | | |
| | | $ | 7,010 | | | $ | 6,326 | | | $ | 5,572 | | | $ | (6,548 | ) | | $ | 12,360 | |
| | | | | | | | | | | | | | | | |
80
|
| | | | | | | | | | | | | | | | | | | | |
| As of June 30, 2012 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| ASSETS | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| Receivables- | | | | | | | | | | |
| Customers | | 457 |
| | — |
| | — |
| | — |
| | 457 |
|
| Affiliated companies | | 464 |
| | 482 |
| | 297 |
| | (706 | ) | | 537 |
|
| Other | | 67 |
| | 25 |
| | 4 |
| | — |
| | 96 |
|
| Notes receivable from affiliated companies | | 155 |
| | 1,653 |
| | 152 |
| | (1,732 | ) | | 228 |
|
| Materials and supplies, at average cost | | 68 |
| | 272 |
| | 208 |
| | — |
| | 548 |
|
| Derivatives | | 265 |
| | — |
| | — |
| | — |
| | 265 |
|
| Prepayments and other | | 3 |
| | 15 |
| | 1 |
| | — |
| | 19 |
|
| | | 1,479 |
| | 2,454 |
| | 662 |
| | (2,438 | ) | | 2,157 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | |
| In service | | 89 |
| | 5,620 |
| | 6,051 |
| | (385 | ) | | 11,375 |
|
| Less — Accumulated provision for depreciation | | 30 |
| | 1,872 |
| | 2,594 |
| | (182 | ) | | 4,314 |
|
| | | 59 |
| | 3,748 |
| | 3,457 |
| | (203 | ) | | 7,061 |
|
| Construction work in progress | | 28 |
| | 187 |
| | 704 |
| | — |
| | 919 |
|
| | | 87 |
| | 3,935 |
| | 4,161 |
| | (203 | ) | | 7,980 |
|
| INVESTMENTS: | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | — |
| | — |
| | 1,250 |
| | — |
| | 1,250 |
|
| Investment in affiliated companies | | 6,241 |
| | — |
| | — |
| | (6,241 | ) | | — |
|
| Other | | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| | | 6,241 |
| | 7 |
| | 1,250 |
| | (6,241 | ) | | 1,257 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | |
| Accumulated deferred income tax benefits | | — |
| | 261 |
| | — |
| | (261 | ) | | — |
|
| Customer intangibles | | 118 |
| |
|
| | — |
| | — |
| | 118 |
|
| Goodwill | | 24 |
| |
|
| | — |
| | — |
| | 24 |
|
| Property taxes | | — |
| | 20 |
| | 23 |
| | — |
| | 43 |
|
| Unamortized sale and leaseback costs | | — |
| | 4 |
| | — |
| | 114 |
| | 118 |
|
| Derivatives | | 110 |
| |
|
| | — |
| | — |
| | 110 |
|
| Other | | 86 |
| | 160 |
| | 1 |
| | (110 | ) | | 137 |
|
| | | 338 |
| | 445 |
| | 24 |
| | (257 | ) | | 550 |
|
| | | $ | 8,145 |
| | $ | 6,841 |
| | $ | 6,097 |
| | $ | (9,139 | ) | | $ | 11,944 |
|
| | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | |
| Currently payable long-term debt | | $ | 1 |
| | $ | 646 |
| | $ | 518 |
| | $ | (21 | ) | | $ | 1,144 |
|
| Short-term borrowings- | | | | | | | | | | |
| Affiliated companies | | 1,597 |
| | 135 |
| | — |
| | (1,732 | ) | | — |
|
| Accounts payable- | | | | | | | | | | |
| Affiliated companies | | 739 |
| | 279 |
| | 305 |
| | (715 | ) | | 608 |
|
| Other | | 173 |
| | 133 |
| | — |
| | — |
| | 306 |
|
| Accrued taxes | | 23 |
| | 20 |
| | 27 |
| | (8 | ) | | 62 |
|
| Derivatives | | 219 |
| | — |
| | — |
| | — |
| | 219 |
|
| Other | | 68 |
| | 124 |
| | 13 |
| | 37 |
| | 242 |
|
| | | 2,820 |
| | 1,337 |
| | 863 |
| | (2,439 | ) | | 2,581 |
|
| CAPITALIZATION: | | | | | | | | | | |
| Total equity | | 3,704 |
| | 3,413 |
| | 2,810 |
| | (6,223 | ) | | 3,704 |
|
| Long-term debt and other long-term obligations | | 1,482 |
| | 1,657 |
| | 580 |
| | (1,219 | ) | | 2,500 |
|
| | | 5,186 |
| | 5,070 |
| | 3,390 |
| | (7,442 | ) | | 6,204 |
|
| NONCURRENT LIABILITIES: | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | — |
| | — |
| | — |
| | 909 |
| | 909 |
|
| Accumulated deferred income taxes | | 28 |
| | — |
| | 572 |
| | (164 | ) | | 436 |
|
| Asset retirement obligations | | — |
| | 29 |
| | 905 |
| | — |
| | 934 |
|
| Retirement benefits | | 34 |
| | 145 |
| | — |
| | — |
| | 179 |
|
| Lease market valuation liability | | — |
| | 148 |
| | — |
| | — |
| | 148 |
|
| Other | | 77 |
| | 112 |
| | 367 |
| | (3 | ) | | 553 |
|
| | | 139 |
| | 434 |
| | 1,844 |
| | 742 |
| | 3,159 |
|
| | | $ | 8,145 |
| | $ | 6,841 |
| | $ | 6,097 |
| | $ | (9,139 | ) | | $ | 11,944 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
ASSETS | | | | | | | | | | | | | | | | | | | | |
CURRENT ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | — | | | $ | 9 | | | $ | — | | | $ | — | | | $ | 9 | |
| Receivables- | | | | | | | | | | | | | | | | | | | | |
| Customers | | | 366 | | | | — | | | | — | | | | — | | | | 366 | |
| Associated companies | | | 333 | | | | 357 | | | | 126 | | | | (338 | ) | | | 478 | |
| Other | | | 21 | | | | 56 | | | | 13 | | | | — | | | | 90 | |
| Notes receivable from associated companies | | | 34 | | | | 189 | | | | 174 | | | | — | | | | 397 | |
| Materials and supplies, at average cost | | | 41 | | | | 276 | | | | 228 | | | | — | | | | 545 | |
| Derivatives | | | 182 | | | | — | | | | — | | | | — | | | | 182 | |
| Prepayments and other | | | 48 | | | | 10 | | | | 1 | | | | — | | | | 59 | |
| | | | | | | | | | | | | | | | |
| | | | 1,025 | | | | 897 | | | | 542 | | | | (338 | ) | | | 2,126 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | |
| In service | | | 96 | | | | 6,198 | | | | 5,412 | | | | (385 | ) | | | 11,321 | |
| Less — Accumulated provision for depreciation | | | 17 | | | | 2,020 | | | | 2,162 | | | | (175 | ) | | | 4,024 | |
| | | | | | | | | | | | | | | | |
| | | | 79 | | | | 4,178 | | | | 3,250 | | | | (210 | ) | | | 7,297 | |
| Construction work in progress | | | 9 | | | | 520 | | | | 534 | | | | — | | | | 1,063 | |
| | | | | | | | | | | | | | | | |
| | | | 88 | | | | 4,698 | | | | 3,784 | | | | (210 | ) | | | 8,360 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
INVESTMENTS: | | | | | | | | | | | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | | — | | | | — | | | | 1,146 | | | | — | | | | 1,146 | |
| Investment in associated companies | | | 4,942 | | | | — | | | | — | | | | (4,942 | ) | | | — | |
| Other | | | — | | | | 12 | | | | — | | | | — | | | | 12 | |
| | | | | | | | | | | | | | | | |
| | | | 4,942 | | | | 12 | | | | 1,146 | | | | (4,942 | ) | | | 1,158 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income tax benefits | | | 43 | | | | 412 | | | | — | | | | (455 | ) | | | — | |
| Customer intangibles | | | 134 | | | | — | | | | — | | | | — | | | | 134 | |
| Goodwill | | | 24 | | | | — | | | | — | | | | — | | | | 24 | |
| Property taxes | | | — | | | | 16 | | | | 25 | | | | — | | | | 41 | |
| Unamortized sale and leaseback costs | | | — | | | | 10 | | | | — | | | | 63 | | | | 73 | |
| Derivatives | | | 98 | | | | — | | | | — | | | | — | | | | 98 | |
| Other | | | 21 | | | | 71 | | | | 14 | | | | (58 | ) | | | 48 | |
| | | | | | | | | | | | | | | | |
| | | | 320 | | | | 509 | | | | 39 | | | | (450 | ) | | | 418 | |
| | | | | | | | | | | | | | | | |
| | | $ | 6,375 | | | $ | 6,116 | | | $ | 5,511 | | | $ | (5,940 | ) | | $ | 12,062 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | |
CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Currently payable long-term debt | | $ | 101 | | | $ | 419 | | | $ | 632 | | | $ | (20 | ) | | $ | 1,132 | |
| Short-term borrowings- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | — | | | | 12 | | | | — | | | | — | | | | 12 | |
| Accounts payable- | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 351 | | | | 213 | | | | 250 | | | | (347 | ) | | | 467 | |
| Other | | | 139 | | | | 102 | | | | — | | | | — | | | | 241 | |
| Derivatives | | | 266 | | | | — | | | | — | | | | — | | | | 266 | |
| Other | | | 56 | | | | 183 | | | | 46 | | | | 37 | | | | 322 | |
| | | | | | | | | | | | | | | | |
| | | | 913 | | | | 929 | | | | 928 | | | | (330 | ) | | | 2,440 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | |
| Common stockholder’s equity | | | 3,788 | | | | 2,515 | | | | 2,414 | | | | (4,929 | ) | | | 3,788 | |
| Long-term debt and other long-term obligations | | | 1,519 | | | | 2,119 | | | | 793 | | | | (1,250 | ) | | | 3,181 | |
| | | | | | | | | | | | | | | | |
| | | | 5,307 | | | | 4,634 | | | | 3,207 | | | | (6,179 | ) | | | 6,969 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | | — | | | | — | | | | — | | | | 959 | | | | 959 | |
| Accumulated deferred income taxes | | | — | | | | — | | | | 448 | | | | (390 | ) | | | 58 | |
| Asset retirement obligations | | | — | | | | 27 | | | | 865 | | | | — | | | | 892 | |
| Retirement benefits | | | 48 | | | | 237 | | | | — | | | | — | | | | 285 | |
| Lease market valuation liability | | | — | | | | 217 | | | | — | | | | — | | | | 217 | |
| Derivatives | | | 81 | | | | — | | | | — | | | | — | | | | 81 | |
| Other | | | 26 | | | | 72 | | | | 63 | | | | — | | | | 161 | |
| | | | | | | | | | | | | | | | |
| | | | 155 | | | | 553 | | | | 1,376 | | | | 569 | | | | 2,653 | |
| | | | | | | | | | | | | | | | |
| | | $ | 6,375 | | | $ | 6,116 | | | $ | 5,511 | | | $ | (5,940 | ) | | $ | 12,062 | |
| | | | | | | | | | | | | | | | |
81
|
| | | | | | | | | | | | | | | | | | | | |
| As of December 31, 2011 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| ASSETS | | | | | | | | | | |
| CURRENT ASSETS: | | | | | | | | | | |
| Cash and cash equivalents | | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
| Receivables- | | | | | | | | | | |
| Customers | | 424 |
| | — |
| | — |
| | — |
| | 424 |
|
| Affiliated companies | | 476 |
| | 643 |
| | 262 |
| | (781 | ) | | 600 |
|
| Other | | 28 |
| | 20 |
| | 13 |
| | — |
| | 61 |
|
| Notes receivable from affiliated companies | | 155 |
| | 1,346 |
| | 69 |
| | (1,187 | ) | | 383 |
|
| Materials and supplies, at average cost | | 60 |
| | 232 |
| | 200 |
| | — |
| | 492 |
|
| Derivatives | | 219 |
| | — |
| | — |
| | — |
| | 219 |
|
| Prepayments and other | | 11 |
| | 26 |
| | 1 |
| | — |
| | 38 |
|
| | | 1,373 |
| | 2,274 |
| | 545 |
| | (1,968 | ) | | 2,224 |
|
| PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | |
| In service | | 84 |
| | 5,573 |
| | 5,711 |
| | (385 | ) | | 10,983 |
|
| Less — Accumulated provision for depreciation | | 28 |
| | 1,813 |
| | 2,449 |
| | (180 | ) | | 4,110 |
|
| | | 56 |
| | 3,760 |
| | 3,262 |
| | (205 | ) | | 6,873 |
|
| Construction work in progress | | 29 |
| | 195 |
| | 790 |
| | — |
| | 1,014 |
|
| | | 85 |
| | 3,955 |
| | 4,052 |
| | (205 | ) | | 7,887 |
|
| INVESTMENTS: | | | | | | | | | | |
| Nuclear plant decommissioning trusts | | — |
| | — |
| | 1,223 |
| | — |
| | 1,223 |
|
| Investment in affiliated companies | | 5,700 |
| | — |
| | — |
| | (5,700 | ) | | — |
|
| Other | | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| | | 5,700 |
| | 7 |
| | 1,223 |
| | (5,700 | ) | | 1,230 |
|
| DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | |
| Accumulated deferred income tax benefits | | 10 |
| | 307 |
| | — |
| | (317 | ) | | — |
|
| Customer intangibles | | 123 |
| | — |
| | — |
| | — |
| | 123 |
|
| Goodwill | | 24 |
| | — |
| | — |
| | — |
| | 24 |
|
| Property taxes | | — |
| | 20 |
| | 23 |
| | — |
| | 43 |
|
| Unamortized sale and leaseback costs | | — |
| | 5 |
| | — |
| | 75 |
| | 80 |
|
| Derivatives | | 79 |
| | — |
| | — |
| | — |
| | 79 |
|
| Other | | 89 |
| | 99 |
| | 3 |
| | (62 | ) | | 129 |
|
| | | 325 |
| | 431 |
| | 26 |
| | (304 | ) | | 478 |
|
| | | $ | 7,483 |
| | $ | 6,667 |
| | $ | 5,846 |
| | $ | (8,177 | ) | | $ | 11,819 |
|
| | | | | | | | | | | |
| LIABILITIES AND CAPITALIZATION | | | | | | | | | | |
| CURRENT LIABILITIES: | | | | | | | | | | |
| Currently payable long-term debt | | $ | 1 |
| | $ | 411 |
| | $ | 513 |
| | $ | (20 | ) | | $ | 905 |
|
| Short-term borrowings- | | | | | | | | | | |
| Affiliated companies | | 1,065 |
| | 89 |
| | 32 |
| | (1,186 | ) | | — |
|
| Accounts payable- | | | | | | | | | | |
| Affiliated companies | | 777 |
| | 228 |
| | 211 |
| | (780 | ) | | 436 |
|
| Other | | 99 |
| | 121 |
| | — |
| | — |
| | 220 |
|
| Accrued taxes | | 84 |
| | 42 |
| | 110 |
| | (9 | ) | | 227 |
|
| Derivatives | | 189 |
| | — |
| | — |
| | — |
| | 189 |
|
| Other | | 62 |
| | 141 |
| | 16 |
| | 42 |
| | 261 |
|
| | | 2,277 |
| | 1,032 |
| | 882 |
| | (1,953 | ) | | 2,238 |
|
| CAPITALIZATION: | | | | | | | | | | |
| Total equity | | 3,577 |
| | 3,097 |
| | 2,587 |
| | (5,684 | ) | | 3,577 |
|
| Long-term debt and other long-term obligations | | 1,483 |
| | 1,905 |
| | 641 |
| | (1,230 | ) | | 2,799 |
|
| | | 5,060 |
| | 5,002 |
| | 3,228 |
| | (6,914 | ) | | 6,376 |
|
| NONCURRENT LIABILITIES: | | | | | | | | | | |
| Deferred gain on sale and leaseback transaction | | — |
| | — |
| | — |
| | 925 |
| | 925 |
|
| Accumulated deferred income taxes | | 12 |
| | — |
| | 510 |
| | (236 | ) | | 286 |
|
| Asset retirement obligations | | — |
| | 28 |
| | 876 |
| | — |
| | 904 |
|
| Retirement benefits | | 56 |
| | 300 |
| | — |
| | — |
| | 356 |
|
| Lease market valuation liability | | — |
| | 171 |
| | — |
| | — |
| | 171 |
|
| Other | | 78 |
| | 134 |
| | 350 |
| | 1 |
| | 563 |
|
| | | 146 |
| | 633 |
| | 1,736 |
| | 690 |
| | 3,205 |
|
| | | $ | 7,483 |
| | $ | 6,667 |
| | $ | 5,846 |
| | $ | (8,177 | ) | | $ | 11,819 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2011 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | |
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (329 | ) | | $ | 321 | | | $ | 200 | | | $ | (10 | ) | | $ | 182 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | — | | | | 140 | | | | 107 | | | | — | | | | 247 | |
| Short-term borrowings, net | | | 453 | | | | 77 | | | | — | | | | — | | | | 530 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | (135 | ) | | | (192 | ) | | | (155 | ) | | | 10 | | | | (472 | ) |
| Other | | | (9 | ) | | | (1 | ) | | | (1 | ) | | | — | | | | (11 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) financing activities | | | 309 | | | | 24 | | | | (49 | ) | | | 10 | | | | 294 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (6 | ) | | | (109 | ) | | | (219 | ) | | | — | | | | (334 | ) |
| Sales of investment securities held in trusts | | | — | | | | — | | | | 513 | | | | — | | | | 513 | |
| Purchases of investment securities held in trusts | | | — | | | | — | | | | (545 | ) | | | — | | | | (545 | ) |
| Loans to associated companies, net | | | 28 | | | | (221 | ) | | | 100 | | | | — | | | | (93 | ) |
| Customer acquisition costs | | | (2 | ) | | | — | | | | — | | | | — | | | | (2 | ) |
| Other | | | — | | | | (18 | ) | | | — | | | | — | | | | (18 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) investing activities | | | 20 | | | | (348 | ) | | | (151 | ) | | | — | | | | (479 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net change in cash and cash equivalents | | | — | | | | (3 | ) | | | — | | | | — | | | | (3 | ) |
| Cash and cash equivalents at beginning of period | | | — | | | | 9 | | | | — | | | | — | | | | 9 | |
| | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | 6 | | | $ | — | | | $ | — | | | $ | 6 | |
| | | | | | | | | | | | | | | | |
82
|
| | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2012 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| | | | | | | | | | | |
| NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (525 | ) | | $ | 308 |
| | $ | 446 |
| | $ | (10 | ) | | $ | 219 |
|
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
| New Financing- | | | | | | | | | | |
| Long-term debt | | — |
| | 52 |
| | 30 |
| | — |
| | 82 |
|
| Short-term borrowings, net | | 532 |
| | 46 |
| | — |
| | (578 | ) | | — |
|
| Redemptions and Repayments- | | | | | | | | | | |
| Long-term debt | | — |
| | (63 | ) | | (87 | ) | | 10 |
| | (140 | ) |
| Short-term borrowings, net | | — |
| | — |
| | (32 | ) | | 32 |
| | — |
|
| Other | | (1 | ) | | (4 | ) | | (1 | ) | | — |
| | (6 | ) |
| Net cash provided from (used for) financing activities | | 531 |
| | 31 |
| | (90 | ) | | (536 | ) | | (64 | ) |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
| Property additions | | (5 | ) | | (44 | ) | | (254 | ) | | — |
| | (303 | ) |
| Proceeds from assets sale | | — |
| | 17 |
| | — |
| | — |
| | 17 |
|
| Sales of investment securities held in trusts | | — |
| | — |
| | 109 |
| | — |
| | 109 |
|
| Purchases of investment securities held in trusts | | — |
| | — |
| | (127 | ) | | — |
| | (127 | ) |
| Loans to affiliated companies, net | | 1 |
| | (308 | ) | | (84 | ) | | 546 |
| | 155 |
|
| Other | | (2 | ) | | (4 | ) | | — |
| | — |
| | (6 | ) |
| Net cash provided from (used for) investing activities | | (6 | ) | | (339 | ) | | (356 | ) | | 546 |
| | (155 | ) |
Net change in cash and cash equivalents | | — |
| | — |
| | — |
| | — |
| | — |
|
| Cash and cash equivalents at beginning of period | | — |
| | 7 |
| | — |
| | — |
| | 7 |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | 7 |
| | $ | — |
| | $ | — |
| | $ | 7 |
|
FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2010 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | |
| | | (In millions) | |
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (223 | ) | | $ | 163 | | | $ | 287 | | | $ | (9 | ) | | $ | 218 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| New Financing- | | | | | | | | | | | | | | | | | | | | |
| Short-term borrowings, net | | | — | | | | 76 | | | | — | | | | — | | | | 76 | |
| Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | |
| Long-term debt | | | — | | | | (261 | ) | | | (43 | ) | | | 9 | | | | (295 | ) |
| Other | | | (1 | ) | | | — | | | | — | | | | — | | | | (1 | ) |
| | | | | | | | | | | | | | | | |
| Net cash used for financing activities | | | (1 | ) | | | (185 | ) | | | (43 | ) | | | 9 | | | | (220 | ) |
| | | | | | | | | | | | | | | | |
| |
CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | |
| Property additions | | | (4 | ) | | | (333 | ) | | | (229 | ) | | | — | | | | (566 | ) |
| Proceeds from asset sales | | | — | | | | 116 | | | | — | | | | — | | | | 116 | |
| Sales of investment securities held in trusts | | | — | | | | — | | | | 957 | | | | — | | | | 957 | |
| Purchases of investment securities held in trusts | | | — | | | | — | | | | (979 | ) | | | — | | | | (979 | ) |
| Loans to associated companies, net | | | 332 | | | | 241 | | | | 58 | | | | — | | | | 631 | |
| Customer acquisition costs | | | (105 | ) | | | — | | | | — | | | | — | | | | (105 | ) |
| Leasehold improvement payments to associated companies | | | — | | | | — | | | | (51 | ) | | | — | | | | (51 | ) |
| Other | | | 1 | | | | (2 | ) | | | — | | | | — | | | | (1 | ) |
| | | | | | | | | | | | | | | | |
| Net cash provided from (used for) investing activities | | | 224 | | | | 22 | | | | (244 | ) | | | — | | | | 2 | |
| | | | | | | | | | | | | | | | |
| |
| Net change in cash and cash equivalents | | | — | | | | — | | | | — | | | | — | | | | — | |
| Cash and cash equivalents at beginning of period | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | |
83
|
| | | | | | | | | | | | | | | | | | | | |
| For the Six Months Ended June 30, 2011 | | FES | | FGCO | | NGC | | Eliminations | | Consolidated |
| | | (In millions) |
| | | | | | | | | | | |
| NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES | | $ | (329 | ) | | $ | 321 |
| | $ | 200 |
| | $ | (10 | ) | | $ | 182 |
|
CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | |
| New Financing- | | | | | | | | | | |
| Long-term debt | | — |
| | 140 |
| | 107 |
| | — |
| | 247 |
|
| Short-term borrowings, net | | 453 |
| | 77 |
| | — |
| | — |
| | 530 |
|
| Redemptions and Repayments- | | | | | | | | | | |
| Long-term debt | | (135 | ) | | (192 | ) | | (155 | ) | | 10 |
| | (472 | ) |
| Other | | (9 | ) | | (1 | ) | | (1 | ) | | — |
| | (11 | ) |
| Net cash used for financing activities | | 309 |
| | 24 |
| | (49 | ) | | 10 |
| | 294 |
|
| | | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | |
| Property additions | | (6 | ) | | (109 | ) | | (219 | ) | | — |
| | (334 | ) |
| Sales of investment securities held in trusts | | — |
| | — |
| | 513 |
| | — |
| | 513 |
|
| Purchases of investment securities held in trusts | | — |
| | — |
| | (545 | ) | | — |
| | (545 | ) |
| Loans to affiliated companies, net | | 28 |
| | (221 | ) | | 100 |
| | — |
| | (93 | ) |
| Other | | (2 | ) | | (18 | ) | | — |
| | — |
| | (20 | ) |
| Net cash provided from (used for) investing activities | | 20 |
| | (348 | ) | | (151 | ) | | — |
| | (479 | ) |
Net change in cash and cash equivalents | | — |
| | (3 | ) | | — |
| | — |
| | (3 | ) |
| Cash and cash equivalents at beginning of period | | — |
| | 9 |
| | — |
| | — |
| | 9 |
|
| Cash and cash equivalents at end of period | | $ | — |
| | $ | 6 |
| | $ | — |
| | $ | — |
| | $ | 6 |
|
11. SEGMENT INFORMATION
| | |
Item 2. | | Management’s Discussion and Analysis of Registrant and Subsidiaries
|
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Earnings available to FirstEnergy Corp. were $181 million, or basic and diluted earnings of $0.43 per share of common stock, compared with $265 million, or basic and diluted earnings of $0.87 per share of common stock inDuring the second quarter of 2010. Earnings available to2012, FirstEnergy Corp. insuccessfully completed the first six monthsintegration of 2011 were $231 million or basic and diluted earnings of $0.61 per share of common stock, compared with $420 million or basic earnings of $1.38 ($1.37 diluted) per share of common stock in the first six months of 2010. The principal reasons for the decreases are summarized below.
| | | | | | | | | |
| | | Three Months | | | Six Months | |
| Change In Basic Earnings Per Share From Prior Year(1) | | Ended June 30 | | | Ended June 30 | |
| Basic Earnings Per Share - 2010 | | $ | 0.87 | | | $ | 1.38 | |
| Non-core asset sales/impairments | | | (0.01 | ) | | | (0.04 | ) |
| Trust securities impairments | | | 0.01 | | | | 0.02 | |
| Mark-to-market adjustments | | | (0.10 | ) | | | (0.02 | ) |
| Income tax charge from healthcare legislation - 2010 | | | — | | | | 0.04 | |
| Regulatory charges - 2011 | | | (0.01 | ) | | | (0.05 | ) |
| Regulatory charges - 2010 | | | — | | | | 0.08 | |
| Litigation resolution | | | (0.06 | ) | | | (0.07 | ) |
| Merger related costs | | | (0.02 | ) | | | (0.31 | ) |
Segment operating results -(2) | | | | | | | | |
| Regulated Distribution | | | 0.02 | | | | — | |
| Competitive Energy Services | | | (0.15 | ) | | | (0.24 | ) |
| Interest expense, net of amounts capitalized | | | (0.04 | ) | | | (0.08 | ) |
| Merger accounting — commodity contracts | | | (0.08 | ) | | | (0.12 | ) |
Net merger accretion(3) | | | 0.02 | | | | 0.06 | |
| Settlement of uncertain tax positions | | | (0.03 | ) | | | (0.05 | ) |
| Other expenses | | | 0.01 | | | | 0.01 | |
| | | | | | | |
| Basic Earnings Per Share - 2011 | | $ | 0.43 | | | $ | 0.61 | |
| | | | | | | |
| | |
(1) | | Amounts shown are net of income tax effect |
|
|
(2) | | Excludes amounts that are shown separately |
(3) | | Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately |
Merger
On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger between 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 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 AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.
In connection with the merger, FirstEnergy recorded approximately $7 million of merger transaction costs during each of the second quarter of 2011 and 2010, and approximately $89 million and $21 million of merger transaction costs during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. FirstEnergy’s consolidated financial statements include Allegheny’s results of operationsits IT business networks and financial position effective February 25, 2011. In addition, duringsystems. An important element of this system integration was the three months ended June 30, 2011, $10 million of merger integration costs and $8 million of charges from merger settlements approved by regulatory agencies were recognized. Incapability to modify the first six months of 2011, $85 million of merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.
FirstEnergy expects to achieve the 2011 merger benefits target resulting from the merger with Allegheny. Through June 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of approximately $132 million pre-tax on an annual basis, or 63% of the $210 million annual target. The $132 million realized from savings initiatives completed through June, along with the impact of initiatives still underway, will be reflected in earnings throughout 2011.
84
Operational Matters
TrAIL
On May 19, 2011, TrAIL’s 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.
ATSI Integrated into PJM
On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy’s generation, transmission and distribution facilities are now in PJM.
Perry Refueling
On June 7, 2011, the Perry Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.
New Nuclear Emergency Operations Facilities
In June 2011, FENOC broke ground for new Emergency Operations Facilities for the Beaver Valley Power Station and Perry Nuclear Power Plant. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies. FENOC is expected to break ground for a similar facility for the Davis-Besse Nuclear Power Station in August 2011.
Fremont Energy Center
On July 28, 2011, FirstEnergy closed on the previously announced sale of Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million,segment reporting to reflect additionalhow management now views and makes investment decisions regarding the distribution and transmission export capacity up to 707 MW.
Financial Matters
On April 29, 2011, Met-Ed redeemed $13.69 millionoperations of pollution control revenue bonds at par value.
On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.
On May 31, 2011, JCP&L and Met-Ed repurchased $500 million and $150 million, respectively, of their equity from FirstEnergy to maintain an appropriate capital structure.
On June 1, 2011, FGCO repurchased $40 million of pollution control revenue bonds and is holding those bonds for future remarketing or refinancing.
On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated entities and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.
On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of FMBs previously delivered to certain of the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.
Regulatory Matters
NYSEG Ruling
On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.
85
Marginal transmission loss recovery
On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC’s order. On June 14, 2011, the Commonwealth Court affirmed the PPUC’s decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court’s decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending outcome of the court appeals.
FIRSTENERGY’S BUSINESS
With the completion of the Allegheny merger in the first quarter of 2011, 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 now consistent with the internal financial reportingreports used by FirstEnergy’sFirstEnergy'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.
Prior to the change 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 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’sFirstEnergy's operating segments for 20102011 have been reclassified to conform to the current presentation.
The key changes in FirstEnergy’sFirstEnergy's reportable segments during the firstsecond quarter of 20112012 consisted primarilyprincipally of including 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 “Other” segment, were placed into this segment.
A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. Thefederally-regulated transmission assets and operations of JCP&L, Met-Ed, Penelec,ME, PN, MP, PE and WP, remainthat were previously reported within the Regulated Distribution segment.
AE Supply, an operator of generation facilities that was acquired as part ofsegment, with the merger with Allegheny, was placed intorenamed Regulated Transmission Segment. There were no changes to the Competitive Energy Services segment.
or Other / Corporate Segments. FirstEnergy continues to havethreereportable operating segments — Regulated Distribution, Regulated Transmission and Competitive Energy Services.
Financial information for each of FirstEnergy’s reportable segments is presented in the tabletables below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES, OE and the UtilitiesJCP&L do not have separate reportable operating segments.
The Regulated Distribution segment distributes electricity through FirstEnergy’stenutility operating companies, serving approximately 6six millioncustomers within 67,000 65,000square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland.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 whichthat 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 (POLR, SOS 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.
86
The Regulated Transmission segment, previously known in part as the Regulated Independent Transmission segmentSegment, transmits electricity through transmission lines.lines owned and operated by certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and independent transmission companies (ATSI, TrAIL and PATH). Its revenues are primarily derived from the formula rate recovery ofrates that recover costs and provide a return on investment fortransmission capital expenditures in connection with TrAIL, PATH and other projects and revenuesinvestment. Revenues are also derived from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenuesrevenue from operation of a portion ofoperating the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.
The Competitive Energy Services segment, through FES and AE Supply, supplies electric powerelectricity to end-use customers through retail and wholesale arrangements, including associated company power sales to meet 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, Michigan, New Jersey and Maryland, Michigan and New Jersey. FES purchases the entire outputprovision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including 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.
Utilities. This business segment controls approximately 20,000 17,000MWs of capacity, excluding approximately2,700MWs from unregulated plants expected to be deactivated, (see Note 8, Regulatory Matters, of the Combined Notes to Consolidated Financial Statements) 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 related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.
The Other and Reconciling Adjustments segment / Corporate Segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. Reconciling adjustments primarily consist of elimination of intersegment transactions.
Segment Financial Information
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Regulated Distribution | | Regulated Transmission | | Competitive Energy Services | | Other/Corporate | | Reconciling Adjustments | | Consolidated |
| | | (In millions) |
| June 30, 2012 | | | | | | | | | | | | |
| External revenues | | $ | 2,095 |
| | $ | 184 |
| | $ | 1,616 |
| | $ | (24 | ) | | $ | (2 | ) | | $ | 3,869 |
|
| Internal revenues | | — |
| | — |
| | 209 |
| | — |
| | (209 | ) | | — |
|
| Total revenues | | 2,095 |
| | 184 |
| | 1,825 |
| | (24 | ) | | (211 | ) | | 3,869 |
|
| Depreciation and amortization | | 215 |
| | 29 |
| | 103 |
| | 8 |
| | (1 | ) | | 354 |
|
| Investment income | | 19 |
| | — |
| | 6 |
| | 1 |
| | (13 | ) | | 13 |
|
| Net interest charges | | 132 |
| | 22 |
| | 59 |
| | 42 |
| | — |
| | 255 |
|
| Income taxes | | 94 |
| | 31 |
| | 14 |
| | (25 | ) | | 13 |
| | 127 |
|
| Net income | | 161 |
| | 52 |
| | 25 |
| | (42 | ) | | (8 | ) | | 188 |
|
| Total assets | | 25,787 |
| | 4,473 |
| | 17,216 |
| | 572 |
| | — |
| | 48,048 |
|
| Total goodwill | | 5,025 |
| | 526 |
| | 893 |
| | — |
| | — |
| | 6,444 |
|
| Property additions | | 177 |
| | 59 |
| | 150 |
| | 26 |
| | — |
| | 412 |
|
| | | | | | | | | | | | | |
| June 30, 2011 | | | | | | | | | | | | |
| External revenues | | $ | 2,409 |
| | $ | 182 |
| | $ | 1,495 |
| | $ | (30 | ) | | $ | (8 | ) | | $ | 4,048 |
|
| Internal revenues | | — |
| | — |
| | 318 |
| | — |
| | (306 | ) | | 12 |
|
| Total revenues | | 2,409 |
| | 182 |
| | 1,813 |
| | (30 | ) | | (314 | ) | | 4,060 |
|
| Depreciation and amortization | | 232 |
| | 28 |
| | 109 |
| | 8 |
| | — |
| | 377 |
|
| Investment income | | 25 |
| | — |
| | 16 |
| | — |
| | (10 | ) | | 31 |
|
| Net interest charges | | 134 |
| | 24 |
| | 69 |
| | 19 |
| | (1 | ) | | 245 |
|
| Income taxes | | 100 |
| | 33 |
| | 12 |
| | (30 | ) | | (1 | ) | | 114 |
|
| Net income | | 171 |
| | 57 |
| | 21 |
| | (51 | ) | | (5 | ) | | 193 |
|
| Total assets | | 25,069 |
| | 4,202 |
| | 17,146 |
| | 1,179 |
| | — |
| | 47,596 |
|
| Total goodwill | | 5,025 |
| | 526 |
| | 885 |
| | — |
| | — |
| | 6,436 |
|
| Property additions | | 266 |
| | 81 |
| | 197 |
| | 25 |
| | — |
| | 569 |
|
| | | | | | | | | | | | | |
| Six Months Ended | | | | | | | | | | | | |
| June 30, 2012 | | | | | | | | | | | | |
| External revenues | | $ | 4,420 |
| | $ | 370 |
| | $ | 3,222 |
| | $ | (47 | ) | | $ | (20 | ) | | $ | 7,945 |
|
| Internal revenues | | — |
| | — |
| | 477 |
| | — |
| | (475 | ) | | 2 |
|
| Total revenues | | 4,420 |
| | 370 |
| | 3,699 |
| | (47 | ) | | (495 | ) | | 7,947 |
|
| Depreciation and amortization | | 435 |
| | 61 |
| | 203 |
| | 16 |
| | (1 | ) | | 714 |
|
| Investment income | | 42 |
| | 1 |
| | 12 |
| | 1 |
| | (32 | ) | | 24 |
|
| Net interest charges | | 264 |
| | 45 |
| | 113 |
| | 63 |
| | (1 | ) | | 484 |
|
| Income taxes | | 187 |
| | 66 |
| | 97 |
| | (41 | ) | | 40 |
| | 349 |
|
| Net income | | 318 |
| | 112 |
| | 166 |
| | (69 | ) | | (33 | ) | | 494 |
|
| Total assets | | 25,787 |
| | 4,473 |
| | 17,216 |
| | 572 |
| | — |
| | 48,048 |
|
| Total goodwill | | 5,025 |
| | 526 |
| | 893 |
| | — |
| | — |
| | 6,444 |
|
| Property additions | | 443 |
| | 122 |
| | 393 |
| | 43 |
| | — |
| | 1,001 |
|
| | | | | | | | | | | | | |
| June 30, 2011 | | | | | | | | | | | | |
| External revenues | | $ | 4,632 |
| | $ | 295 |
| | $ | 2,736 |
| | $ | (53 | ) | | $ | (18 | ) | | $ | 7,592 |
|
| Internal revenues | | — |
| | — |
| | 661 |
| | — |
| | (617 | ) | | 44 |
|
| Total revenues | | 4,632 |
| | 295 |
| | 3,397 |
| | (53 | ) | | (635 | ) | | 7,636 |
|
| Depreciation and amortization | | 473 |
| | 50 |
| | 197 |
| | 14 |
| | — |
| | 734 |
|
| Investment income | | 48 |
| | — |
| | 21 |
| | 1 |
| | (18 | ) | | 52 |
|
| Net interest charges | | 256 |
| | 41 |
| | 122 |
| | 39 |
| | — |
| | 458 |
|
| Income taxes | | 158 |
| | 47 |
| | 21 |
| | (30 | ) | | 29 |
| | 225 |
|
| Net income | | 267 |
| | 80 |
| | 36 |
| | (105 | ) | | (38 | ) | | 240 |
|
| Total assets | | 25,069 |
| | 4,202 |
| | 17,146 |
| | 1,179 |
| | — |
| | 47,596 |
|
| Total goodwill | | 5,025 |
| | 526 |
| | 885 |
| | — |
| | — |
| | 6,436 |
|
| Property additions | | 381 |
| | 170 |
| | 411 |
| | 56 |
| | — |
| | 1,018 |
|
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
Earnings available to FirstEnergy Corp. in the second quarter of 2012 were $187 million, or basic and diluted earnings of $0.45 per share of common stock, compared with $203 million, or basic and diluted earnings of $0.48 per share of common stock in the second quarter of 2011. Earnings available to FirstEnergy Corp. in the first six months of 2012 were $493 million or basic and diluted earnings of $1.18 per share of common stock, compared with $255 million or basic and diluted earnings of $0.67 per share of common stock in the first six months of 2011. The principal reasons for the changes in basic earnings per share are summarized below.
|
| | | | | | | | |
| Change In Basic Earnings Per Share From Prior Year | | Three Months Ended June 30 | | Six Months Ended June 30 |
| Basic Earnings Per Share - 2011 | | $ | 0.48 |
| | $ | 0.67 |
|
Segment operating results(1) - | | | | |
| Regulated Distribution | | (0.01 | ) | | (0.04 | ) |
| Regulated Transmission | | — |
| | (0.01 | ) |
| Competitive Energy Services | | (0.06 | ) | | (0.04 | ) |
| Regulatory charges | | — |
| | 0.02 |
|
| Income Tax Charge – retiree prescription drug subsidy | | (0.02 | ) | | (0.04 | ) |
| Merger-related costs | | 0.02 |
| | 0.36 |
|
| Impact of non-core asset sales / impairments | | 0.03 |
| | 0.06 |
|
| Mark-to-market adjustments | | 0.01 |
| | 0.09 |
|
| Merger accounting — commodity contracts | | 0.04 |
| | 0.04 |
|
| Plant closing costs | | (0.07 | ) | | (0.13 | ) |
| Litigation resolution | | 0.05 |
| | 0.05 |
|
Net merger accretion(1)(2) | | — |
| | 0.17 |
|
| Depreciation | | (0.01 | ) | | — |
|
| Interest expense, net of amounts capitalized | | 0.01 |
| | 0.02 |
|
| Investment Income | | (0.02 | ) | | (0.02 | ) |
| Other | | — |
| | (0.02 | ) |
| Basic Earnings Per Share - 2012 | | $ | 0.45 |
| | $ | 1.18 |
|
| |
(1) | Excludes amounts that are shown separately. Allegheny results for the three months ended June 30, 2012 and 2011, are included in Segment Operating Results. |
| |
(2) | Includes dilutive effect of shares issued in connection with the Allegheny merger, and three months of Allegheny results in the first three months of 2012 compared to one month during the same period of 2011. |
Operational Matters
Enhancing Transmission System Reliability
On May 29, 2012, FirstEnergy announced plans to construct a series of transmission projects to enhance service reliability across its service area. The projects have been approved by PJM and will include specialized voltage regulating equipment in northern Ohio. In addition to the work in Ohio, approved transmission projects will also be undertaken in Pennsylvania, West Virginia, New Jersey and Maryland as part of FirstEnergy's ongoing commitment to enhance its transmission system reliability. FirstEnergy estimates spending between $700 million - $900 million through 2016 on these projects.
On June 14, 2012, JCP&L announced that it plans to begin work on 17 transmission construction projects over the next six months in its northern and central New Jersey service areas. These projects are part of the multi-year, $200 million LITE program, which began in 2011, to address New Jersey's growing demand for electricity and provide key enhancements to the transmission system designed to improve service reliability for JCP&L's 1.1 million customers. All of the LITE projects are being designed and built specifically to serve only JCP&L customers.
Beaver Valley Unit 1 Returns to Service After Refueling Outage
On May 11, 2012, Beaver Valley Power Station Unit 1 returned to service following an April 9, 2012 shutdown for refueling and maintenance. During the outage, 65 of the 157 fuel assemblies were exchanged and safety inspections were successfully conducted. In addition, maintenance and improvement projects were completed to ensure continued safe and reliable operations. Prior to the outage, Beaver Valley Unit 1 operated safely and reliably for 359 consecutive days during which time it generated more than 9.3 million MWH of electricity. The plant also posted an industry top-decile forced-loss rate of 0.01 percent during the 18 months of operation prior to the outage.
Davis-Besse Returns to Service After Refueling Outage
On June 13, 2012, Davis-Besse Nuclear Power Station returned to service following a May 6, 2012, shutdown for refueling and maintenance. During the outage, 68 of Davis-Besse's 177 fuel assemblies were exchanged and safety inspections, including inspections of the station's steam generators, were successfully conducted. Preventive maintenance and improvement projects also were completed that are designed to promote continued safe and reliable operations.
Storm Costs
During the last weekend of June 2012, MP, PE, WP and OE experienced significant customer outages due to a rare “derecho” wind storm. While projections for restoration costs are not finalized, estimated costs incurred in the third quarter related to this storm are expected to exceed $130 million. Approximately 70% of these estimated expenditures are anticipated to be capital-related. Most of the remaining maintenance costs are expected to be deferred for future recovery. MP and PE do not currently have regulatory authority to defer storm costs, but expect to make a filing in the third quarter of 2012 with the WVPSC requesting deferral of those costs. MP and PE can provide no assurance that they will be successful in getting WVPSC authorization for the deferral of storm costs.
Regulatory Matters
Ohio Electric Security Plan Update
On July 18, 2012, the PUCO approved the Ohio Companies' ESP allowing the Ohio Companies to essentially extend the terms of the current ESP for two additional years and establish electricity prices for their customers through May 31, 2016.
The approved ESP 3 plan will maintain the substantial benefits from the current ESP including:
Freezing current base distribution rates through May 31, 2016;
Continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;
Providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;
Continuing to provide power to shopping and to non-shopping customers as part of the market-based price set through an auction process; and
Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.
The approved ESP 3 plan provides significant additional benefits including:
Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and
Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.
The approved plan reflects the diverse interests and concerns of 19 signatories, including parties that represent residential, low-income, commercial and industrial customers, as well as competitive retail electric suppliers, schools and hospitals.
Ohio Companies Solar Renewable Energy
On April 26, 2012, FirstEnergy announced that its Ohio Companies have met the 2012 benchmarks for in-state solar renewable energy that were established under Ohio's energy law. The benchmarks were met through a successful RFP to secure 10-year SRECs. In Ohio, FirstEnergy supports the development of solar energy resources by purchasing SRECs, which represent the environmental attributes of solar renewable electricity generation. For every MWH of solar renewable electricity generated, an equivalent amount of SRECs are produced. The RFP sought and procured the delivery of 1,000 SRECs produced by generating facilities throughout Ohio for each calendar year beginning in 2012 and continuing through 2021. There were 38 qualified bids received, offering over 15 times the required SRECs being sought under the RFP.
NJBPU Update
In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.
Financial Matters
In the second quarter of 2012, FirstEnergy executed a total of $1.6 billion forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%.
On May 8, 2012, FET entered into a new $1 billion revolving credit facility. In conjunction with this action, an existing $450 million TrAIL revolving credit facility was terminated. On May 9, 2012, FET drew the entire amount to repay $171.3 million of short-term borrowings and to pay $3.2 million in expenses related to the closing. The balance was invested in the unregulated money pool. On May 10, 2012, FE repaid $1.0 billion under the existing $2.0 billion facility. Additionally, FirstEnergy and FES/AE Supply amended their existing $2.0 billion and $2.5 billion revolving credit facilities, respectively. The termination date on both facilities was extended from June 2016 to May 2017 and pricing was reduced to reflect current market conditions.
On August 1, 2012, FGCO mandatorily repurchased approximately $106.5 million of 4.75% PCRBs, which it is holding for future remarketing or refinancing subject to market and other conditions.
FIRSTENERGY’S BUSINESS
During the second quarter of 2012, FirstEnergy successfully completed the integration of AE into its IT business networks and financial systems. An important element of this system integration was the capability to modify the segment reporting to reflect how management now views and makes investment decisions regarding the distribution and transmission operations of FirstEnergy. The external segment reporting is now consistent with the internal financial reports used by FirstEnergy's chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. Disclosures for FirstEnergy's operating segments for 2011 have been reclassified to conform to the current presentation.
The key changes in FirstEnergy's reportable segments during the second quarter of 2012 consisted principally of including the federally-regulated transmission assets and operations of JCP&L, ME, PN, MP, PE and WP, that were previously reported within the Regulated Distribution segment, with the renamed Regulated Transmission Segment. There were no changes to the Competitive Energy Services or Other / Corporate Segments. FirstEnergy continues to havethreereportable operating segments — Regulated Distribution, Regulated Transmission and Competitive Energy Services.
Financial information for each of FirstEnergy’s reportable segments is presented in the tables below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES, OE and JCP&L do not have separate reportable operating segments.
The Regulated Distribution segment distributes electricity through FirstEnergy’stenutility operating companies, serving approximately6 millioncustomers within65,000square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland.This segment also includes regulated electric generation facilities in West Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. Its results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs.
The Regulated Transmission segment, previously known in part as the Regulated Independent Transmission Segment, transmits electricity through transmission lines owned and operated by certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and independent transmission companies (ATSI, TrAIL and PATH). Its revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Revenues are also derived from providing transmission services to electric energy providers, power marketers and revenue from operating the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.
The Competitive Energy Services segment, through FES and AE Supply, supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment controls approximately17,000MWs of capacity, excluding approximately2,700MWs from unregulated plants expected to be deactivated, (see Note 8, Regulatory Matters, of the Combined Notes to Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.
Other and Reconciling Adjustments contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment as well as reconciling adjustments for the elimination of intersegment transactions.transactions. See Note 11, Segment Information, of the Combined Notes to Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. Results fromof operations for the pre-merged companiessix months ended June 30, 2011, include only four months of Allegheny results which have been segregated from the Alleghenypre-merger companies (FirstEnergy and its subsidiaries prior to the merger) for variance reporting and analysis. In addition, Allegheny's results were affected by many of the same factors that influenced the operating results of the pre-merger companies. A reconciliation of segment financial results is provided in Note 1311, Segment Information, to the consolidated financial statements.Combined Notes to Consolidated Financial Statements. Earnings available to FirstEnergy by business segment were as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Three Months Ended | | | Six Months Ended | |
| | | June 30 | | | June 30 | |
| | | | | | | | | | | Increase | | | | | | | | | | | Increase | |
| | | 2011 | | | 2010 | | | (Decrease) | | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions, except per share data) | |
Earnings (Loss) By Business Segment: | | | | | | | | | | | | | | | | | | | | | | | | |
| Regulated Distribution | | $ | 184 | | | $ | 132 | | | $ | 52 | | | $ | 280 | | | $ | 235 | | | $ | 45 | |
| Competitive Energy Services | | | 12 | | | | 121 | | | | (109 | ) | | | 17 | | | | 190 | | | | (173 | ) |
| Regulated Independent Transmission | | | 31 | | | | 11 | | | | 20 | | | | 44 | | | | 23 | | | | 21 | |
| Other and reconciling adjustments* | | | (46 | ) | | | 1 | | | | (47 | ) | | | (110 | ) | | | (28 | ) | | | (82 | ) |
| | | | | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 181 | | | $ | 265 | | | $ | (84 | ) | | $ | 231 | | | $ | 420 | | | $ | (189 | ) |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Basic Earnings Per Share | | $ | 0.43 | | | $ | 0.87 | | | $ | (0.44 | ) | | $ | 0.61 | | | $ | 1.38 | | | $ | (0.77 | ) |
Diluted Earnings Per Share | | $ | 0.43 | | | $ | 0.87 | | | $ | (0.44 | ) | | $ | 0.61 | | | $ | 1.37 | | | $ | (0.76 | ) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Three Months
Ended June 30 | | Six Months
Ended June 30 |
| | 2012 | | 2011 | | Increase (Decrease) | | 2012 | | 2011 | | Increase |
| | (In millions, except per share data) |
| Earnings (Loss) By Business Segment: | | | | | | | | | | | |
| Regulated Distribution | $ | 161 |
| | $ | 171 |
| | $ | (10 | ) | | $ | 318 |
| | $ | 267 |
| | $ | 51 |
|
| Competitive Energy Services | 25 |
| | 21 |
| | 4 |
| | 166 |
| | 36 |
| | 130 |
|
| Regulated Transmission | 52 |
| | 57 |
| | (5 | ) | | 112 |
| | 80 |
| | 32 |
|
Other and reconciling adjustments (1) | (51 | ) | | (46 | ) | | (5 | ) | | (103 | ) | | (128 | ) | | 25 |
|
| Earnings available to FirstEnergy Corp. | $ | 187 |
| | $ | 203 |
| | $ | (16 | ) | | $ | 493 |
| | $ | 255 |
| | $ | 238 |
|
| | | | | | | | | | | | |
| Basic Earnings Per Share | $ | 0.45 |
| | $ | 0.48 |
| | $ | (0.03 | ) | | $ | 1.18 |
| | $ | 0.67 |
| | $ | 0.51 |
|
| Diluted Earnings Per Share | $ | 0.45 |
| | $ | 0.48 |
| | $ | (0.03 | ) | | $ | 1.18 |
| | $ | 0.67 |
| | $ | 0.51 |
|
| | |
* | (1) | Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. |
87
Summary of Results of Operations — Second Quarter 2011 Compared with Second Quarter 2010
Financial results for FirstEnergy’s business segments in the second quarter of 2011 and 2010 were as follows:63
| | | | | | | | | | | | | | | | | | | | | | |
| | | Competitive | | Regulated | | Other and | | | | | | | | | | | | | | |
| | | Regulated | | Energy | | Independent | | Reconciling | | FirstEnergy | | |
| Second Quarter 2011 Financial Results | | Distribution | | Services | | Transmission | | Adjustments | | Consolidated | | |
| Second Quarter 2012 Financial Results | | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) | | | (In millions) |
| Revenues: | | | | | | | | | | | |
| External | | | | | | | | | | | |
| Electric | | $ | 2,352 | | $ | 1,394 | | $ | — | | $ | — | | $ | 3,746 | | | $ | 2,059 |
| | $ | — |
| | $ | 1,527 |
| | $ | 1 |
| | $ | 3,587 |
|
| Other | | 133 | | 101 | | 105 | | | (37 | ) | | 302 | | | 36 |
| | 184 |
| | 89 |
| | (27 | ) | | 282 |
|
| Internal | | — | | 318 | | — | | | (306 | ) | | 12 | | | — |
| | — |
| | 209 |
| | (209 | ) | | — |
|
| | | | | | | | | | | | | |
| Total Revenues | | 2,485 | | 1,813 | | 105 | | | (343 | ) | | 4,060 | | | 2,095 |
| | 184 |
| | 1,825 |
| | (235 | ) | | 3,869 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Expenses: | | |
| Operating Expenses: | | | | | | | | | | | |
| Fuel | | 73 | | 562 | | — | | — | | 635 | | | 57 |
| | — |
| | 598 |
| | 1 |
| | 656 |
|
| Purchased power | | 1,144 | | 382 | | — | | | (306 | ) | | 1,220 | | | 895 |
| | — |
| | 470 |
| | (209 | ) | | 1,156 |
|
| Other operating expenses | | 438 | | 640 | | 19 | | 8 | | 1,105 | | | 393 |
| | 41 |
| | 513 |
| | (33 | ) | | 914 |
|
| Provision for depreciation | | 153 | | 107 | | 15 | | 7 | | 282 | | | 151 |
| | 31 |
| | 103 |
| | 7 |
| | 292 |
|
| Amortization of regulatory assets | | 87 | | — | | 3 | | — | | 90 | | |
| Amortization (deferral) of regulatory assets, net | | | 64 |
| | (2 | ) | | — |
| | — |
| | 62 |
|
| General taxes | | 180 | | 51 | | 8 | | 3 | | 242 | | | 167 |
| | 9 |
| | 49 |
| | 7 |
| | 232 |
|
| | | | | | | | | | | | | |
| Total Expenses | | 2,075 | | 1,742 | | 45 | | | (288 | ) | | 3,574 | | |
| | | | | | | | | | | | | |
| Total Operating Expenses | | | 1,727 |
| | 79 |
| | 1,733 |
| | (227 | ) | | 3,312 |
|
| | | | | | | | | | | | |
| Operating Income | | 410 | | 71 | | 60 | | | (55 | ) | | 486 | | | 368 |
| | 105 |
| | 92 |
| | (8 | ) | | 557 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | |
| Investment income | | 27 | | 15 | | — | | | (11 | ) | | 31 | | | 19 |
| | — |
| | 6 |
| | (12 | ) | | 13 |
|
| Interest expense | | | (148 | ) | | | (79 | ) | | | (12 | ) | | | (26 | ) | | | (265 | ) | | (135 | ) | | (23 | ) | | (71 | ) | | (45 | ) | | (274 | ) |
| Capitalized interest | | 3 | | 12 | | 1 | | 4 | | 20 | | | 3 |
| | 1 |
| | 12 |
| | 3 |
| | 19 |
|
| | | | | | | | | | | | | |
| Total Other Expense | | | (118 | ) | | | (52 | ) | | | (11 | ) | | | (33 | ) | | | (214 | ) | | (113 | ) | | (22 | ) | | (53 | ) | | (54 | ) | | (242 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Income Before Income Taxes | | 292 | | 19 | | 49 | | | (88 | ) | | 272 | | | 255 |
| | 83 |
| | 39 |
| | (62 | ) | | 315 |
|
| Income taxes | | 108 | | 7 | | 18 | | | (32 | ) | | 101 | | | 94 |
| | 31 |
| | 14 |
| | (12 | ) | | 127 |
|
| | | | | | | | | | | | | |
| Net Income (Loss) | | 184 | | 12 | | 31 | | | (56 | ) | | 171 | | |
| Loss attributable to noncontrolling interest | | — | | — | | — | | | (10 | ) | | | (10 | ) | |
| | | | | | | | | | | | | |
| Earnings (loss) available to FirstEnergy Corp. | | $ | 184 | | $ | 12 | | $ | 31 | | $ | (46 | ) | | $ | 181 | | |
| | | | | | | | | | | | | |
| Net Income | | | 161 |
| | 52 |
| | 25 |
| | (50 | ) | | 188 |
|
| Income attributable to noncontrolling interest | | | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Earnings Available to FirstEnergy Corp. | | | $ | 161 |
| | $ | 52 |
| | $ | 25 |
| | $ | (51 | ) | | $ | 187 |
|
88
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| Second Quarter 2010 Financial Results | | Distribution | | | Services | | | Transmission | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 2,243 | | | $ | 739 | | | $ | — | | | $ | — | | | $ | 2,982 | |
| Other | | | 71 | | | | 56 | | | | 59 | | | | (29 | ) | | | 157 | |
| Internal | | | 19 | | | | 539 | | | | — | | | | (558 | ) | | | — | |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | 2,333 | | | | 1,334 | | | | 59 | | | | (587 | ) | | | 3,139 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | — | | | | 350 | | | | — | | | | — | | | | 350 | |
| Purchased power | | | 1,291 | | | | 330 | | | | — | | | | (558 | ) | | | 1,063 | |
| Other operating expenses | | | 331 | | | | 340 | | | | 16 | | | | (14 | ) | | | 673 | |
| Provision for depreciation | | | 106 | | | | 71 | | | | 10 | | | | 3 | | | | 190 | |
| Amortization of regulatory assets | | | 158 | | | | — | | | | 3 | | | | — | | | | 161 | |
| General taxes | | | 138 | | | | 27 | | | | 7 | | | | 4 | | | | 176 | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | 2,024 | | | | 1,118 | | | | 36 | | | | (565 | ) | | | 2,613 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 309 | | | | 216 | | | | 23 | | | | (22 | ) | | | 526 | |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 28 | | | | 13 | | | | — | | | | (10 | ) | | | 31 | |
| Interest expense | | | (125 | ) | | | (57 | ) | | | (6 | ) | | | (19 | ) | | | (207 | ) |
| Capitalized interest | | | 1 | | | | 24 | | | | 1 | | | | 14 | | | | 40 | |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (96 | ) | | | (20 | ) | | | (5 | ) | | | (15 | ) | | | (136 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 213 | | | | 196 | | | | 18 | | | | (37 | ) | | | 390 | |
| Income taxes | | | 81 | | | | 75 | | | | 7 | | | | (29 | ) | | | 134 | |
| | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | 132 | | | | 121 | | | | 11 | | | | (8 | ) | | | 256 | |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | (9 | ) | | | (9 | ) |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 132 | | | $ | 121 | | | $ | 11 | | | $ | 1 | | | $ | 265 | |
| | | | | | | | | | | | | | | | |
89
64
| | | | | | | | | | | | | | | | | | | | | |
| Changes Between Second Quarter 2011 | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| and Second Quarter 2010 Financial | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| Results Increase (Decrease) | | Distribution | | | Services | | | Transmission | | | Adjustment | | | Consolidated | |
| | | (In millions) | |
| | | | | | | | | | | | | | | | | | | | | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 109 | | | $ | 655 | | | $ | — | | | $ | — | | | $ | 764 | |
| Other | | | 62 | | | | 45 | | | | 46 | | | | (8 | ) | | | 145 | |
| Internal | | | (19 | ) | | | (221 | ) | | | — | | | | 252 | | | | 12 | |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | 152 | | | | 479 | | | | 46 | | | | 244 | | | | 921 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 73 | | | | 212 | | | | — | | | | — | | | | 285 | |
| Purchased power | | | (147 | ) | | | 52 | | | | — | | | | 252 | | | | 157 | |
| Other operating expenses | | | 107 | | | | 300 | | | | 3 | | | | 22 | | | | 432 | |
| Provision for depreciation | | | 47 | | | | 36 | | | | 5 | | | | 4 | | | | 92 | |
| Amortization of regulatory assets | | | (71 | ) | | | — | | | | — | | | | — | | | | (71 | ) |
| General taxes | | | 42 | | | | 24 | | | | 1 | | | | (1 | ) | | | 66 | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | 51 | | | | 624 | | | | 9 | | | | 277 | | | | 961 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 101 | | | | (145 | ) | | | 37 | | | | (33 | ) | | | (40 | ) |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | (1 | ) | | | 2 | | | | — | | | | (1 | ) | | | — | |
| Interest expense | | | (23 | ) | | | (22 | ) | | | (6 | ) | | | (7 | ) | | | (58 | ) |
| Capitalized interest | | | 2 | | | | (12 | ) | | | — | | | | (10 | ) | | | (20 | ) |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (22 | ) | | | (32 | ) | | | (6 | ) | | | (18 | ) | | | (78 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 79 | | | | (177 | ) | | | 31 | | | | (51 | ) | | | (118 | ) |
| Income taxes | | | 27 | | | | (68 | ) | | | 11 | | | | (3 | ) | | | (33 | ) |
| | | | | | | | | | | | | | | | |
| Net Income | | | 52 | | | | (109 | ) | | | 20 | | | | (48 | ) | | | (85 | ) |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | (1 | ) | | | (1 | ) |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 52 | | | $ | (109 | ) | | $ | 20 | | | $ | (47 | ) | | $ | (84 | ) |
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| Second Quarter 2011 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | | | | | | | | | |
| External | | | | | | | | | | |
| Electric | | $ | 2,352 |
| | $ | — |
| | $ | 1,394 |
| | $ | — |
| | $ | 3,746 |
|
| Other | | 57 |
| | 182 |
| | 101 |
| | (38 | ) | | 302 |
|
| Internal | | — |
| | — |
| | 318 |
| | (306 | ) | | 12 |
|
| Total Revenues | | 2,409 |
| | 182 |
| | 1,813 |
| | (344 | ) | | 4,060 |
|
| | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | |
| Fuel | | 73 |
| | — |
| | 561 |
| | 1 |
| | 635 |
|
| Purchased power | | 1,145 |
| | — |
| | 381 |
| | (306 | ) | | 1,220 |
|
| Other operating expenses | | 402 |
| | 30 |
| | 625 |
| | 8 |
| | 1,065 |
|
| Provision for depreciation | | 145 |
| | 26 |
| | 109 |
| | 7 |
| | 287 |
|
| Amortization of regulatory assets, net | | 87 |
| | 2 |
| | — |
| | 1 |
| | 90 |
|
| General taxes | | 177 |
| | 10 |
| | 51 |
| | 4 |
| | 242 |
|
| Total Operating Expenses | | 2,029 |
| | 68 |
| | 1,727 |
| | (285 | ) | | 3,539 |
|
| | | | | | | | | | | |
| Operating Income | | 380 |
| | 114 |
| | 86 |
| | (59 | ) | | 521 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | |
| Investment income | | 25 |
| | — |
| | 16 |
| | (10 | ) | | 31 |
|
| Interest expense | | (136 | ) | | (25 | ) | | (80 | ) | | (24 | ) | | (265 | ) |
| Capitalized interest | | 2 |
| | 1 |
| | 11 |
| | 6 |
| | 20 |
|
| Total Other Expense | | (109 | ) | | (24 | ) | | (53 | ) | | (28 | ) | | (214 | ) |
| | | | | | | | | | | |
| Income Before Income Taxes | | 271 |
| | 90 |
| | 33 |
| | (87 | ) | | 307 |
|
| Income taxes | | 100 |
| | 33 |
| | 12 |
| | (31 | ) | | 114 |
|
| Net Income | | 171 |
| | 57 |
| | 21 |
| | (56 | ) | | 193 |
|
| Loss attributable to noncontrolling interest | | — |
| | — |
| | — |
| | (10 | ) | | (10 | ) |
| Earnings Available to FirstEnergy Corp. | | $ | 171 |
| | $ | 57 |
| | $ | 21 |
| | $ | (46 | ) | | $ | 203 |
|
|
| | | | | | | | | | | | | | | | | | | | |
Changes Between Second Quarter 2012 and Second Quarter 2011 Financial Results Increase (Decrease) | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | | | | | | | | | |
| External | | | | | | | | | | |
| Electric | | $ | (293 | ) | | $ | — |
| | $ | 133 |
| | $ | 1 |
| | $ | (159 | ) |
| Other | | (21 | ) | | 2 |
| | (12 | ) | | 11 |
| | (20 | ) |
| Internal | | — |
| | — |
| | (109 | ) | | 97 |
| | (12 | ) |
| Total Revenues | | (314 | ) | | 2 |
| | 12 |
| | 109 |
| | (191 | ) |
| | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | |
| Fuel | | (16 | ) | | — |
| | 37 |
| | — |
| | 21 |
|
| Purchased power | | (250 | ) | | — |
| | 89 |
| | 97 |
| | (64 | ) |
| Other operating expenses | | (9 | ) | | 11 |
| | (112 | ) | | (41 | ) | | (151 | ) |
| Provision for depreciation | | 6 |
| | 5 |
| | (6 | ) | | — |
| | 5 |
|
| Amortization (deferral) of regulatory assets, net | | (23 | ) | | (4 | ) | | — |
| | (1 | ) | | (28 | ) |
| General taxes | | (10 | ) | | (1 | ) | | (2 | ) | | 3 |
| | (10 | ) |
| Total Operating Expenses | | (302 | ) | | 11 |
| | 6 |
| | 58 |
| | (227 | ) |
| | | | | | | | | | | |
| Operating Income | | (12 | ) | | (9 | ) | | 6 |
| | 51 |
| | 36 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | |
| Investment income | | (6 | ) | | — |
| | (10 | ) | | (2 | ) | | (18 | ) |
| Interest expense | | 1 |
| | 2 |
| | 9 |
| | (21 | ) | | (9 | ) |
| Capitalized interest | | 1 |
| | — |
| | 1 |
| | (3 | ) | | (1 | ) |
| Total Other Expense | | (4 | ) | | 2 |
| | — |
| | (26 | ) | | (28 | ) |
| | | | | | | | | | | |
| Income Before Income Taxes | | (16 | ) | | (7 | ) | | 6 |
| | 25 |
| | 8 |
|
| Income taxes | | (6 | ) | | (2 | ) | | 2 |
| | 19 |
| | 13 |
|
| Net Income | | (10 | ) | | (5 | ) | | 4 |
| | 6 |
| | (5 | ) |
| Income attributable to noncontrolling interest | | — |
| | — |
| | — |
| | 11 |
| | 11 |
|
| Earnings Available to FirstEnergy Corp. | | $ | (10 | ) | | $ | (5 | ) | | $ | 4 |
| | $ | (5 | ) | | $ | (16 | ) |
Regulated Distribution — Second Quarter 20112012 Compared with Second Quarter 20102011
Net income increaseddecreased by $52$10 million in the second quarter of 20112012 compared to the second quartersame period of 20102011, primarily due to earnings from the Allegheny companies and increased operating margins from the pre-merger companies as a result of reduced revenues, partially offset by decreased purchased power costs partially offset by reduced revenues.and other operating expenses in the second quarter of 2012.
90
Revenues —
The increase$314 million decrease in total revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended June 30 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Pre-merger companies: | | | | | | | | | | | | |
| Distribution services | | $ | 810 | | | $ | 851 | | | $ | (41 | ) |
| | | | | | | | | | |
| Generation sales: | | | | | | | | | | | | |
| Retail | | | 747 | | | | 1,097 | | | | (350 | ) |
| Wholesale | | | 104 | | | | 180 | | | | (76 | ) |
| | | | | | | | | | |
| Total generation sales | | | 851 | | | | 1,277 | | | | (426 | ) |
| | | | | | | | | | |
| Transmission | | | 51 | | | | 141 | | | | (90 | ) |
| Other | | | 66 | | | | 64 | | | | 2 | |
| | | | | | | | | | |
| Total pre-merger companies | | | 1,778 | | | | 2,333 | | | | (555 | ) |
| | | | | | | | | | |
| Allegheny companies | | | 707 | | | | — | | | | 707 | |
| | | | | | | | | | |
| Total Revenues | | $ | 2,485 | | | $ | 2,333 | | | $ | 152 | |
| | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Increase |
| Revenues by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| | | | | | | |
| Distribution services | | $ | 936 |
| | $ | 966 |
| | $ | (30 | ) |
| Generation sales: | | | | | | |
| Retail | | 961 |
| | 1,166 |
| | (205 | ) |
| Wholesale | | 86 |
| | 172 |
| | (86 | ) |
| Total generation sales | | 1,047 |
| | 1,338 |
| | (291 | ) |
| Transmission | | 61 |
| | 41 |
| | 20 |
|
| Other | | 51 |
| | 64 |
| | (13 | ) |
| Total Revenues | | $ | 2,095 |
| | $ | 2,409 |
| | $ | (314 | ) |
The decrease in distribution service revenues forservices revenue primarily reflected the pre-merger companies reflects lower transition revenues duesuspension of Ohio's deferred distribution cost recovery rider in December 2011 and an NJBPU-approved reduction to the completion of transition cost recovery for CEI in December 2010,JCP&L NUG Rider which became effective on March 1, 2012, partially offset by increased rates associated witha PAPUC-approved increase to the recovery of deferred distribution costs.ME and PN NUG Rider which also became effective on March 1, 2012. Distribution deliveries (excluding the Allegheny companies) decreasedincreased by 1.1%0.9% in the second quarter of 20112012 from the second quartersame period of 2010. The change in distribution2011. Distribution deliveries by customer class isare summarized in the following table:
| | | | | | | | | | | | | |
| | | | | | | | | | | Increase | |
| Electric Distribution KWH Deliveries | | 2011 | | | 2010 | | | (Decrease) | |
| | | (in thousands) | | | | | |
| Pre-merger companies: | | | | | | | | | | | | |
| Residential | | | 8,623 | | | | 8,663 | | | | (0.5 | )% |
| Commercial | | | 7,926 | | | | 8,121 | | | | (2.4 | )% |
| Industrial | | | 8,798 | | | | 8,846 | | | | (0.5 | )% |
| Other | | | 126 | | | | 132 | | | | (4.5 | )% |
| | | | | | | | | | |
| Total pre-merger companies | | | 25,473 | | | | 25,762 | | | | (1.1 | )% |
| | | | | | | | | | |
| Allegheny companies | | | 9,527 | | | | — | | | | — | |
| | | | | | | | | | |
| Total Electric Distribution KWH Deliveries | | | 35,000 | | | | 25,762 | | | | 35.9 | % |
| | | | | | | | | | |
|
| | | | | | | | | |
| | | Three Months
Ended June 30 | | Increase |
| Electric Distribution MWH Deliveries | | 2012 | | 2011 | | (Decrease) |
| | | (in thousands) | | |
| | | | | | | |
| Residential | | 11,832 |
| | 11,958 |
| | (1.1 | )% |
| Commercial | | 10,564 |
| | 10,460 |
| | 1.0 | % |
| Industrial | | 12,784 |
| | 12,433 |
| | 2.8 | % |
| Other | | 151 |
| | 149 |
| | 1.3 | % |
| Total Electric Distribution MWH Deliveries | | 35,331 |
| | 35,000 |
| | 0.9 | % |
Lower deliveries to residential customers reflect declining average customer consumption and commercial customers reflected decreased weather-related usageslightly reduced residential accounts. Commercial class deliveries increased due to load growth in the second quarter of 2011 as cooling degree days decreased by 17.3% from the same period in 2010, and soft economic conditions affecting the commercial sector. In the industrial sector, KWHMWH deliveries decreasedincreased by2.8% primarily due to increased deliveries of 4% to steel customers, 2% to automotive customers and 2% to petroleum customers, partially offset by increaseda 3% decrease in deliveries to steel and electrical equipment customers of 11% and 15%, respectively.chemical customers.
The following table summarizes the price and volume factors contributing to the $426$291 milliondecrease in generation revenues for the pre-merger companies in the second quarter of 20112012 compared to the second quartersame period of 2010:2011:
| | | | | |
| | | Increase | |
| Source of Change in Generation Revenues | | (Decrease) | |
| | | (In millions) | |
| | | | | |
| Retail: | | | | |
| Effect of decrease in sales volumes | | $ | (447 | ) |
| Change in prices | | | 96 | |
| | | | |
| | | | (351 | ) |
| | | | |
| Wholesale: | | | | |
| Effect of decrease in sales volumes | | | (8 | ) |
| Change in prices | | | (67 | ) |
| | | | |
| | | | (75 | ) |
| | | | |
| Net Decrease in Generation Revenues | | $ | (426 | ) |
| | | | |
91
|
| | | | |
| Source of Change in Generation Revenues | | Decrease |
| | | (In millions) |
| Retail: | | |
| Effect of decrease in sales volumes | | $ | (152 | ) |
| Change in prices | | (53 | ) |
| | | (205 | ) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | (62 | ) |
| Change in prices | | (24 | ) |
| | | (86 | ) |
| Decrease in Generation Revenues | | $ | (291 | ) |
The decrease in retail generation sales volume was primarily due to increased customer shopping in the Utilities' service territories ofduring the pre-merger companies in the second quarter of 2011,2012, compared with the second quartersame period of 2010.2011. This increase in customer shopping is expected to continue. Total generation provided by alternative suppliers as a percentage of total KWHMWH deliveries increased to 77%79% from 61%77% for the Ohio companiesCompanies, 65% from 53% for the Pennsylvania Companies and to 55%51% from 10%45% for Met-Ed’s and Penelec’s service areas.JCP&L.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelecof $86 million in the second quarter of 2012 was a result of the expiration of a NUG contract in August 2011 and lower PJM market. market prices.
Transmission revenues increased $20 million primarily due tothe implementation of Ohio's NMB transmission rider in June of 2011, which recovers network integration transmission service charges as described below, partially offset by lower RTO revenue resulting from decreased $90congestion prices.
Other revenue decreased $13 million primarily due to the absence in 2012 of revenue from the sale of certain pole attachment lease rights in June 2011.
Operating Expenses —
Total operating expenses decreased by $302 million due to the termination of Met-Ed’s and Penelec’s TSC rates 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.following:
The Allegheny companies added $707 million of revenues for the second quarter of 2011, including $155 million for distribution services, $486 million for generation sales and $66 million relating to transmission revenues.
Expenses —
Total expenses increasedFuel expense decreased by $51 million due to the following:
Purchased power costs, excluding the Allegheny companies, were $483 million lower in the second quarter of 2011 due primarily to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $336 million in purchased power costs in the second quarter of 2011.
| | | | | |
| | | Increase | |
| Source of Change in Purchased Power | | (Decrease) | |
| | | (In millions) | |
| Pre-merger companies: | | | | |
| Purchases from non-affiliates: | | | | |
| Change due to decreased unit costs | | $ | (161 | ) |
| Change due to increased volumes | | | 88 | |
| | | | |
| | | | (73 | ) |
| | | | |
| Purchases from FES: | | | | |
| Change due to increased unit costs | | | 20 | |
| Change due to decreased volumes | | | (398 | ) |
| | | | |
| | | | (378 | ) |
| | | | |
| | | | | |
| Increase in costs deferred | | | (32 | ) |
| | | | |
| Total pre-merger companies | | | (483 | ) |
| | | | |
| Purchases by Allegheny companies | | | 336 | |
| | | | |
| Net Decrease in Purchased Power Costs | | $ | (147 | ) |
| | | | |
Transmission expenses decreased $29$16 million primarily due to lower PJMgeneration output from the Fort Martin power station.
Purchased power costs were $250 million lower in the second quarter of 2012 primarily due to increased customer shopping, which reduced purchased power requirements, and lower purchased power prices resulting from lower auction prices during the second quarter of 2012 compared to the same period of 2011.
|
| | | | |
| Source of Change in Purchased Power | | Increase (Decrease) |
| | | (In millions) |
| | | |
| Purchases from non-affiliates: | | |
| Change due to decreased unit costs | | $ | (103 | ) |
| Change due to decreased volumes | | (111 | ) |
| | | (214 | ) |
| Purchases from FES: | | |
| Change due to decreased unit costs | | (11 | ) |
| Change due to decreased volumes | | (99 | ) |
| | | (110 | ) |
| Decrease in costs deferred | | 74 |
|
| Net Decrease in Purchased Power Costs | | $ | (250 | ) |
Transmission expenses increased $23 million during the second quarter of 2012 compared to the same period of 2011, primarily due to network integration transmission service expenses that, prior to June 2011, were incurred by the generation supplier, and congestion costs of $70 million for Met-Ed and Penelec,are now being recovered through the NMB transmission rider discussed above, partially offset by transmissionlower
congestion costs.
Depreciation expense increased $6 million primarily due to higher asset removal costs incurred by JCP&L.
Regulatory asset amortization expense decreased $23 million due to the following:
| |
| ◦ | The scheduled suspension of the rider recovery of deferred distribution costs in December 2011, |
| |
| ◦ | The completion of JCP&L's NUG deferred cost recovery, |
| |
| ◦ | Partially offset by the recovery in Ohio of residential generation credits for electric heating discounts, which began in September 2011, and increased recovery of energy efficiency expenses. |
General taxes decreased by $10 million primarily due a decrease in gross receipts taxes partially offset by an increase in property taxes.
Regulated generation operation and maintenance expenses fordecreased by $6 million primarily due to the Allegheny companies of $41upcoming anticipated plant deactivations.
Expenses related to storm activity decreased $12 million in the second quarter of 2011. Met-Ed and Penelec defer or amortize2012 compared to the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.
same period in 2011.Energy Efficiency program costs, which are also recovered through rates, increasedExpenses were further decreased by $43 million.
The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.
Net amortization of regulatory assets decreased $71$15 million due primarily to reduced transition cost recovery andsynergies achieved in connection with the Allegheny merger.
Other Expense —
Other expense increased deferral of energy efficiency program costs.
| • | | Fuel expenses for MP were $73 million in the second quarter of 2011. |
|
| • | | Operating expenses for the Allegheny companies were $95 million in the second quarter of 2011. |
|
| • | | Depreciation expense for the Allegheny companies was $48 million in the second quarter of 2011. |
92
Merger-related costs increased $4$4 million in the second quarter of 2012 primarily due to lower investment income on OE's and TE's NDT assets.
Regulated Transmission — Second Quarter 2012 Compared with Second Quarter 2011
Net income decreased by $5 million in the second quarter of 2012 compared to the same period of 2010.
General taxes increased $42 million2011 primarily due to property taxes and gross receipts taxes incurredincreased operating expenses.
Revenues —
Total revenues increased by the Allegheny companies in the second quarter of 2011.
Other Expense —
Other expense increased $22$2 million in the second quarter of 2011 primarily due to interest expense on debt of the Allegheny companies.
Regulated Independent Transmission — Second Quarter 2011 Compared with Second Quarter 2010
Net income increased by $20 million in the second quarter of 2011 compared to the second quarter of 2010 due to earnings associated witha higher TrAIL and PATH ($22 million), partially offset by decreased earnings for ATSI ($1 million).
Revenues —rate base.
Revenues by transmission asset owner are shown in the following table:
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| Revenues by | | Ended June 30 | | | Increase | |
| Transmission Asset Owner | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| ATSI | | $ | 54 | | | $ | 59 | | | $ | (5 | ) |
| TrAIL | | | 46 | | | | — | | | | 46 | |
| PATH | | | 5 | | | | — | | | | 5 | |
| | | | | | | | | | |
| Total Revenues | | $ | 105 | | | $ | 59 | | | $ | 46 | |
| | | | | | | | | | |
|
| | | | | | | | | | | | |
| Revenues by | | Three Months
Ended June 30 | | |
| Transmission Asset Owner | | 2012 | | 2011 | | Increase |
| | | (In millions) |
| ATSI | | $ | 54 |
| | $ | 54 |
| | $ | — |
|
| TrAIL | | 49 |
| | 47 |
| | 2 |
|
| PATH | | 4 |
| | 4 |
| | — |
|
| Utilities | | 77 |
| | 77 |
| | — |
|
| Total Revenues | | $ | 184 |
| | $ | 182 |
| | $ | 2 |
|
Operating Expenses —
Total operating expenses increased by $9$11 million principally due to TrAILthe following:
Operation and PATH operating expenses.
Other Expense —
Other expensemaintenance expenses increased $6by $11 million primarily due to increased vegetation management costs resulting from additional miles trimmed in the second quarter of 20112012 compared to the same period in 2011.
Depreciation expense increased by $5 million primarily due to additionalthe TrAIL project in-servicing during May 2011.
Net amortization of regulatory assets expense decreased by $4 million primarily due to the completion in May 2011 of ATSI's deferred vegetation management cost recovery.
Other Expense —
Other expense decreased $2 million in the second quarter of 2012 due to lower net interest expense, associated with TrAIL.related to the refinancing of the transmission credit facility.
Competitive Energy Services — Second Quarter 20112012 Compared with Second Quarter 20102011
Net income decreasedincreased by $109$4 million in the second quarter of 2011,2012, compared to the second quartersame period of 2010, primarily2011, due to reduced sales margins, non-core asset impairments and the effect of mark-to-market adjustments.higher retail revenues partially offset by increased operating expenses.
Revenues —
Total revenues increased by $479$12 million in the second quarter of 20112012 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies,wholesale sales, partially offset by a decline in net POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the second quarter of 2011.
93
The increase in total revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended June 30 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Direct and Governmental Aggregation | | $ | 925 | | | $ | 586 | | | $ | 339 | |
| POLR and Structured Sales | | | 231 | | | | 615 | | | | (384 | ) |
| Wholesale | | | 66 | | | | 77 | | | | (11 | ) |
| Transmission | | | 30 | | | | 19 | | | | 11 | |
| RECs | | | 12 | | | | — | | | | 12 | |
| Other | | | 38 | | | | 37 | | | | 1 | |
| Allegheny Companies | | | 511 | | | | — | | | | 511 | |
| | | | | | | | | | |
Total Revenues | | $ | 1,813 | | | $ | 1,334 | | | $ | 479 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct and Governmental Aggregation | | $ | 26 | | | | | | | | | |
| POLR and Structured Sales | | | 185 | | | | | | | | | |
| Wholesale | | | 267 | | | | | | | | | |
| Transmission | | | 32 | | | | | | | | | |
| Other | | | 1 | | | | | | | | | |
| | | | | | | | | | | | |
Total Revenues | | $ | 511 | | | | | | | | | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Three Months | | | | |
| | | Ended June 30 | | | Increase | |
| MWH Sales by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In thousands) | | | | | |
| Direct | | | 11,547 | | | | 7,004 | | | | 64.9 | % |
| Governmental Aggregation | | | 3,970 | | | | 2,715 | | | | 46.2 | % |
| POLR and Structured Sales | | | 3,718 | | | | 11,600 | | | | (67.9 | )% |
| Wholesale | | | 395 | | | | 1,108 | | | | (64.4 | )% |
| Allegheny Companies | | | 8,051 | | | | — | | | | — | |
| | | | | | | | | | |
Total Sales | | | 27,681 | | | | 22,427 | | | | 23.4 | % |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct | | | 425 | | | | | | | | | |
| POLR | | | 2,169 | | | | | | | | | |
| Structured Sales | | | 846 | | | | | | | | | |
| Wholesale | | | 4,611 | | | | | | | | | |
| | | | | | | | | | | | |
Total Sales | | | 8,051 | | | | | | | | | |
| | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Three Months
Ended June 30 | | Increase |
| Revenues by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Direct and Governmental Aggregation | | $ | 1,055 |
| | $ | 951 |
| | $ | 104 |
|
| POLR and Structured Sales | | 295 |
| | 416 |
| | (121 | ) |
| Wholesale | | 386 |
| | 333 |
| | 53 |
|
| Transmission | | 42 |
| | 62 |
| | (20 | ) |
| RECs | | — |
| | 12 |
| | (12 | ) |
| Other | | 47 |
| | 39 |
| | 8 |
|
| Total Revenues | | $ | 1,825 |
| | $ | 1,813 |
| | $ | 12 |
|
| | | | | | | |
|
| | | | | | | | | |
| | | Three Months
Ended June 30 | | Increase |
| MWH Sales by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In thousands) | | |
| Direct | | 13,937 |
| | 11,972 |
| | 16.4 | % |
| Governmental Aggregation | | 4,744 |
| | 3,970 |
| | 19.5 | % |
| POLR and Structured Sales | | 5,379 |
| | 6,733 |
| | (20.1 | )% |
| Wholesale | | 4,846 |
| | 5,006 |
| | (3.2 | )% |
| Total MWH Sales | | 28,906 |
| | 27,681 |
| | 4.4 | % |
| | | | | | | |
The increase in combined direct and governmental aggregation revenues of $339$104 million resulted from the acquisition of new residential, commercial and industrial customers. Our customer base increased to 2.0 million industrial, commercial and residential customers as wellof June 2012 as newcompared to 1.7 million in June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation contracts with communities in Ohio, providing generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million at the end of June 2010. Partially offsetting the increase, were sales to residential and small commercial customers that were adversely affected by weather in thegiven declining market served that was 17% cooler than in 2010.prices.
The decrease in combined POLR and structured revenues of $384$121 million was due primarily to lower sales volumes for POLR sales to Met-Ed, Penelec and the Ohio Companies, partiallyME and PN due to an increased migration of customers away from their default service. Revenues were also adversely impacted by lower unit prices. The decline in POLR sales reflects a continued focus on other sales channels by FES.
Wholesale revenues increased $53 million due to increased gains of $147 million on financially settled contracts, which were offset by increased sales to non-associated companies and higher unita $45 million decrease in capacity revenues resulting from the lower capacity prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for direct retail and aggregation sales.
Wholesale revenues decreased $11 million due to reduced generation available for sale in the wholesale market.RTO zone effective June 1, 2012, and a $49 million decrease in short-term (net hourly positions) transactions.
94
The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):revenues:
| | | | | |
| | | Increase | |
| Source of Change in Direct and Governmental Aggregation | | (Decrease) | |
| | | (In millions) | |
| Direct Sales: | | | | |
| Effect of increase in sales volumes | | $ | 267 | |
| Change in prices | | | (13 | ) |
| | | | |
| | | | 254 | |
| | | | |
| Governmental Aggregation: | | | | |
| Effect of increase in sales volumes | | | 80 | |
| Change in prices | | | 5 | |
| | | | |
| | | | 85 | |
| | | | |
| Net Increase in Direct and Governmental Aggregation Revenues | | $ | 339 | |
| | | | |
| | | | | |
| | | Increase | |
| Source of Change in POLR and Structured Revenues | | (Decrease) | |
| | | (In millions) | |
| POLR: | | | | |
| Effect of decrease in sales volumes | | $ | (418 | ) |
| Change in prices | | | 34 | |
| | | | |
| | | | (384 | ) |
| | | | |
|
| | | | |
| Source of Change in Direct and Governmental Aggregation | | Increase (Decrease) |
| | | (In millions) |
| Direct and Governmental Aggregation: | | |
| Effect of increase in sales volumes | | $ | 165 |
|
| Change in prices | | (61 | ) |
| | | $ | 104 |
|
| | | | |
| | Increase | |
Source of Change in Wholesale Revenues | | (Decrease) | |
| | (In millions) | |
Wholesale: | | | | |
Effect of decrease in sales volumes | | | (49 | ) |
Change in prices | | | 38 | |
| | | |
| | | (11 | ) |
| | | |
|
| | | | |
| Source of Change in POLR and Structured Revenues | | Increase (Decrease) |
| | | (In millions) |
| POLR and Structured: | | |
| Effect of decrease in sales volumes | | $ | (84 | ) |
| Change in prices | | (37 | ) |
| | | $ | (121 | ) |
|
| | | | |
| Source of Change in Wholesale Revenues | | Increase (Decrease) |
| | | (In millions) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | $ | (7 | ) |
| Change in prices | | (42 | ) |
| Gain on settled contracts | | 147 |
|
| Capacity revenue | | (45 | ) |
| | | $ | 53 |
|
Transmission revenues decreased by $20 million primarily due to lower congestion revenue.
Operating Expenses —
Total operating expenses increased by $11$6 million in the second quarter of 2012 due to the following:
Fuel costs increased $37 million primarily due to higher volumes consumed ($30 million) and higher unit prices ($7 million). Volumes increased due to higher fossil generation as a result of fewer planned and unplanned outages.
Purchased power costs increased $89 million due to higher volumes ($41 million) and losses on settled contracts ($133 million), partially offset by reduced capacity expenses ($21 million) and lower unit prices ($64 million). The increase in purchased power volume primarily relates to the overall increase in direct and governmental aggregation sales volumes and economic purchases.
Fossil operating costs decreased by $22 million due primarily to lower contractor, materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by severance costs associated with certain fossil units to be deactivated.
Nuclear operating costs increased by $21 million due primarily to higher PJM congestion revenue.contractor and materials and equipment costs. The revenues derived from the sale of RECs increased $12 million in the second quarter of 2011.
Expenses —
Total expenses increased by $624 million in2012 included refueling outages at Davis Besse and Beaver Valley Unit 1, whereas the second quarter of 2011 included a refueling outage at Perry and the conclusion of the Beaver Valley 2 refueling outage that began in the first quarter of 2011.
Transmission expenses decreased by $71 million due to the following:lower congestion, network and loss expenses.
Fuel costsGeneral taxes decreased by $27$2 million due to lower property taxes, partially offset by increases in revenue-related taxes.
Depreciation expense decreased by $6 million primarily due to decreased volumes ($56 million), partially offset by higher unit prices ($29 million). Volumes decreased due toa lower generation at theasset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain fossil units. Higher unit prices reflect increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.
Purchased power costs were unchanged as higher unit costs ($70 million) were offset by lower volumes purchased ($70 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.
Fossil operating costs increased by $18 million due primarily to higher labor, contractor and materials and equipment costs due to in increase in outages, both planned and unplanned, from the previous year.
Nuclear operating costs increased by $33 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.
Transmission expenses increased by $66 million due primarily to increases in PJM of $91 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $25 million due to lower network and line loss costs.
General taxes increased by $10 million due to an increase in revenue-related taxes.
95
Other operating expenses increaseddecreased by $36$40 million primarily due to: a $14 millionto favorable mark-to-market adjustment; a $7 million impairment charge related to non-core assets; and an $8 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Ohio Companies.adjustments on commodity
The inclusion of the Allegheny companies’ operations contributed $488 million to expenses, including a $9 million mark-to-market adjustment relating primarily to power contracts.
contract positions.
Other Expense —
Total other expense in the second quarter of 20112012 was $32 million higher thanflat compared to the second quarter of 2010, primarily due to a $34 million increase in net interest expense partially offset by an increase in investment income ($2 million)2011. The increase inReduced interest expense was primarily due tooffset by lower investment income from the inclusion of the Allegheny companies ($22 million) and lower capitalized interest ($12 million) associated with the completion of the Sammis AQC project in 2010.nuclear decommissioning trusts.
| | | | | |
| | | Increase | |
| Source of Expense Changes | | (Decrease) | |
| | | (In millions) | |
| | | | | |
Allegheny Companies | | | | |
| Fuel | | $ | 238 | |
| Purchased power | | | 53 | |
| Fossil | | | 55 | |
| Transmission | | | 75 | |
| Mark-to-Market | | | 9 | |
| General taxes | | | 11 | |
| Other | | | 15 | |
| Depreciation | | | 32 | |
| | | | |
| Total Expense | | $ | 488 | |
| | | | |
Other — Second Quarter of 20112012 Compared with Second Quarter of 20102011
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a $47$5 milliondecrease in earnings available to FirstEnergy Corp. in the second quarter of 20112012 compared to the same period in 2010.of 2011. The decrease resulted primarily from increased net interest expense ($24 million) and increased income attributable to noncontrolling interest ($11 million) relating to Global Holding, which was de-consolidated in the fourth quarter of 2011, partially offset by lower operating expenses resulting from adverse litigation resolution ($2941 million), decreased capitalized interest ($10 million) resulting from completed construction projects and increased interest expense due to the 2010 termination of interest rate swap agreements ($7 million).lower merger-related costs.
96
Summary of Results of Operations — First Six Months of 20112012 Compared with the First Six Months of 20102011
Financial results for FirstEnergy’s business segments in the first six months of 20112012 and 20102011 were as follows:
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| First Six Months 2011 Financial Results | | Distribution | | | Services | | | Transmission | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | 4,527 | | | $ | 2,556 | | | $ | — | | | $ | — | | | $ | 7,083 | |
| Other | | | 226 | | | | 180 | | | | 172 | | | | (69 | ) | | | 509 | |
| Internal | | | — | | | | 661 | | | | — | | | | (617 | ) | | | 44 | |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | 4,753 | | | | 3,397 | | | | 172 | | | | (686 | ) | | | 7,636 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 97 | | | | 991 | | | | — | | | | — | | | | 1,088 | |
| Purchased power | | | 2,323 | | | | 700 | | | | — | | | | (617 | ) | | | 2,406 | |
| Other operating expenses | | | 824 | | | | 1,288 | | | | 36 | | | | (10 | ) | | | 2,138 | |
| Provision for depreciation | | | 269 | | | | 195 | | | | 25 | | | | 13 | | | | 502 | |
| Amortization of regulatory assets | | | 216 | | | | — | | | | 6 | | | | — | | | | 222 | |
| General taxes | | | 356 | | | | 95 | | | | 16 | | | | 12 | | | | 479 | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | 4,085 | | | | 3,269 | | | | 83 | | | | (602 | ) | | | 6,835 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 668 | | | | 128 | | | | 89 | | | | (84 | ) | | | 801 | |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | 52 | | | | 21 | | | | — | | | | (21 | ) | | | 52 | |
| Interest expense | | | (280 | ) | | | (144 | ) | | | (21 | ) | | | (51 | ) | | | (496 | ) |
| Capitalized interest | | | 4 | | | | 22 | | | | 1 | | | | 11 | | | | 38 | |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (224 | ) | | | (101 | ) | | | (20 | ) | | | (61 | ) | | | (406 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 444 | | | | 27 | | | | 69 | | | | (145 | ) | | | 395 | |
| Income taxes | | | 164 | | | | 10 | | | | 25 | | | | (20 | ) | | | 179 | |
| | | | | | | | | | | | | | | | |
| Net Income (Loss) | | | 280 | | | | 17 | | | | 44 | | | | (125 | ) | | | 216 | |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | (15 | ) | | | (15 | ) |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 280 | | | $ | 17 | | | $ | 44 | | | $ | (110 | ) | | $ | 231 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | Competitive | | Regulated | | Other and | | | | | | | | | | | | | | |
| | | Regulated | | Energy | | Independent | | Reconciling | | FirstEnergy | | |
| First Six Months 2010 Financial Results | | Distribution | | Services | | Transmission | | Adjustments | | Consolidated | | |
| First Six Months 2012 Financial Results | | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) | | | (In millions) |
| Revenues: | | | | | | | | | | | |
| External | | | | | | | | | | | |
| Electric | | $ | 4,641 | | $ | 1,408 | | $ | — | | $ | — | | $ | 6,049 | | | $ | 4,329 |
| | $ | — |
| | $ | 3,058 |
| | $ | 1 |
| | $ | 7,388 |
|
| Other | | 157 | | 106 | | 116 | | | (57 | ) | | 322 | | | 91 |
| | 370 |
| | 164 |
| | (68 | ) | | 557 |
|
| Internal | | 19 | | 1,213 | | — | | | (1,165 | ) | | 67 | | | — |
| | — |
| | 477 |
| | (475 | ) | | 2 |
|
| | | | | | | | | | | | | |
| Total Revenues | | 4,817 | | 2,727 | | 116 | | | (1,222 | ) | | 6,438 | | | 4,420 |
| | 370 |
| | 3,699 |
| | (542 | ) | | 7,947 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | |
| Expenses: | | |
| Operating Expenses: | | | | | | | | | | | |
| Fuel | | — | | 684 | | — | | — | | 684 | | | 97 |
| | — |
| | 1,100 |
| | — |
| | 1,197 |
|
| Purchased power | | 2,686 | | 780 | | — | | | (1,165 | ) | | 2,301 | | | 1,977 |
| | — |
| | 1,000 |
| | (474 | ) | | 2,503 |
|
| Other operating expenses | | 690 | | 692 | | 30 | | | (38 | ) | | 1,374 | | | 828 |
| | 66 |
| | 922 |
| | (90 | ) | | 1,726 |
|
| Provision for depreciation | | 210 | | 148 | | 19 | | 6 | | 383 | | | 297 |
| | 61 |
| | 203 |
| | 16 |
| | 577 |
|
| Amortization of regulatory assets | | 367 | | — | | 6 | | — | | 373 | | |
| Amortization of regulatory assets, net | | | 138 |
| | — |
| | — |
| | (1 | ) | | 137 |
|
| General taxes | | 292 | | 64 | | 14 | | 11 | | 381 | | | 356 |
| | 21 |
| | 110 |
| | 17 |
| | 504 |
|
| | | | | | | | | | | | | |
| Total Expenses | | 4,245 | | 2,368 | | 69 | | | (1,186 | ) | | 5,496 | | |
| | | | | | | | | | | | | |
| Total Operating Expenses | | | 3,693 |
| | 148 |
| | 3,335 |
| | (532 | ) | | 6,644 |
|
| | | | | | | | | | | | |
| Operating Income | | 572 | | 359 | | 47 | | | (36 | ) | | 942 | | | 727 |
| | 222 |
| | 364 |
| | (10 | ) | | 1,303 |
|
| | | | | | | | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | |
| Investment income | | 54 | | 14 | | — | | | (21 | ) | | 47 | | | 42 |
| | 1 |
| | 12 |
| | (31 | ) | | 24 |
|
| Interest expense | | | (250 | ) | | | (113 | ) | | | (11 | ) | | | (46 | ) | | | (420 | ) | | (269 | ) | | (46 | ) | | (136 | ) | | (69 | ) | | (520 | ) |
| Capitalized interest | | 2 | | 47 | | 1 | | 31 | | 81 | | | 5 |
| | 1 |
| | 23 |
| | 7 |
| | 36 |
|
| | | | | | | | | | | | | |
| Total Other Expense | | | (194 | ) | | | (52 | ) | | | (10 | ) | | | (36 | ) | | | (292 | ) | | (222 | ) | | (44 | ) | | (101 | ) | | (93 | ) | | (460 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | |
| Income Before Income Taxes | | 378 | | 307 | | 37 | | | (72 | ) | | 650 | | | 505 |
| | 178 |
| | 263 |
| | (103 | ) | | 843 |
|
| Income taxes | | 143 | | 117 | | 14 | | | (29 | ) | | 245 | | | 187 |
| | 66 |
| | 97 |
| | (1 | ) | | 349 |
|
| | | | | | | | | | | | | |
| Net Income (Loss) | | 235 | | 190 | | 23 | | | (43 | ) | | 405 | | |
| Loss attributable to noncontrolling interest | | — | | — | | — | | | (15 | ) | | | (15 | ) | |
| | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 235 | | $ | 190 | | $ | 23 | | $ | (28 | ) | | $ | 420 | | |
| | | | | | | | | | | | | |
| Net Income | | | 318 |
| | 112 |
| | 166 |
| | (102 | ) | | 494 |
|
| Income attributable to noncontrolling interest | | | — |
| | — |
| | — |
| | 1 |
| | 1 |
|
| Earnings Available to FirstEnergy Corp. | | | $ | 318 |
| | $ | 112 |
| | $ | 166 |
| | $ | (103 | ) | | $ | 493 |
|
97
| | | | | | | | | | | | | | | | | | | | | |
| Changes Between First Six Months 2011 and | | | | | | Competitive | | | Regulated | | | Other and | | | | |
| First Six Months 2010 Financial Results | | Regulated | | | Energy | | | Independent | | | Reconciling | | | FirstEnergy | |
| Increase (Decrease) | | Distribution | | | Services | | | Transmission | | | Adjustments | | | Consolidated | |
| | | (In millions) | |
| Revenues: | | | | | | | | | | | | | | | | | | | | |
| External | | | | | | | | | | | | | | | | | | | | |
| Electric | | $ | (114 | ) | | $ | 1,148 | | | $ | — | | | $ | — | | | $ | 1,034 | |
| Other | | | 69 | | | | 74 | | | | 56 | | | | (12 | ) | | | 187 | |
| Internal | | | (19 | ) | | | (552 | ) | | | — | | | | 548 | | | | (23 | ) |
| | | | | | | | | | | | | | | | |
| Total Revenues | | | (64 | ) | | | 670 | | | | 56 | | | | 536 | | | | 1,198 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Expenses: | | | | | | | | | | | | | | | | | | | | |
| Fuel | | | 97 | | | | 307 | | | | — | | | | — | | | | 404 | |
| Purchased power | | | (363 | ) | | | (80 | ) | | | — | | | | 548 | | | | 105 | |
| Other operating expenses | | | 134 | | | | 596 | | | | 6 | | | | 28 | | | | 764 | |
| Provision for depreciation | | | 59 | | | | 47 | | | | 6 | | | | 7 | | | | 119 | |
| Amortization of regulatory assets | | | (151 | ) | | | — | | | | — | | | | — | | | | (151 | ) |
| General taxes | | | 64 | | | | 31 | | | | 2 | | | | 1 | | | | 98 | |
| | | | | | | | | | | | | | | | |
| Total Expenses | | | (160 | ) | | | 901 | | | | 14 | | | | 584 | | | | 1,339 | |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating Income | | | 96 | | | | (231 | ) | | | 42 | | | | (48 | ) | | | (141 | ) |
| | | | | | | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | | | | | | | | | | | |
| Investment income | | | (2 | ) | | | 7 | | | | — | | | | — | | | | 5 | |
| Interest expense | | | (30 | ) | | | (31 | ) | | | (10 | ) | | | (5 | ) | | | (76 | ) |
| Capitalized interest | | | 2 | | | | (25 | ) | | | — | | | | (20 | ) | | | (43 | ) |
| | | | | | | | | | | | | | | | |
| Total Other Expense | | | (30 | ) | | | (49 | ) | | | (10 | ) | | | (25 | ) | | | (114 | ) |
| | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income Before Income Taxes | | | 66 | | | | (280 | ) | | | 32 | | | | (73 | ) | | | (255 | ) |
| Income taxes | | | 21 | | | | (107 | ) | | | 11 | | | | 9 | | | | (66 | ) |
| | | | | | | | | | | | | | | | |
| Net Income | | | 45 | | | | (173 | ) | | | 21 | | | | (82 | ) | | | (189 | ) |
| Loss attributable to noncontrolling interest | | | — | | | | — | | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | |
| Earnings available to FirstEnergy Corp. | | $ | 45 | | | $ | (173 | ) | | $ | 21 | | | $ | (82 | ) | | $ | (189 | ) |
| | | | | | | | | | | | | | | | |
73
|
| | | | | | | | | | | | | | | | | | | | |
| First Six Months 2011 Financial Results | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | | | | | | | | | |
| External | | | | | | | | | | |
| Electric | | $ | 4,527 |
| | $ | — |
| | $ | 2,556 |
| | $ | — |
| | $ | 7,083 |
|
| Other | | 105 |
| | 295 |
| | 180 |
| | (71 | ) | | 509 |
|
| Internal | | — |
| | — |
| | 661 |
| | (617 | ) | | 44 |
|
| Total Revenues | | 4,632 |
| | 295 |
| | 3,397 |
| | (688 | ) | | 7,636 |
|
| | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | |
| Fuel | | 97 |
| | — |
| | 991 |
| | — |
| | 1,088 |
|
| Purchased power | | 2,323 |
| | — |
| | 700 |
| | (617 | ) | | 2,406 |
|
| Other operating expenses | | 753 |
| | 58 |
| | 1,256 |
| | (9 | ) | | 2,058 |
|
| Provision for depreciation | | 258 |
| | 45 |
| | 197 |
| | 12 |
| | 512 |
|
| Amortization of regulatory assets, net | | 215 |
| | 5 |
| | — |
| | 2 |
| | 222 |
|
| General taxes | | 353 |
| | 19 |
| | 95 |
| | 12 |
| | 479 |
|
| Total Operating Expenses | | 3,999 |
| | 127 |
| | 3,239 |
| | (600 | ) | | 6,765 |
|
| | | | | | | | | | | |
| Operating Income | | 633 |
| | 168 |
| | 158 |
| | (88 | ) | | 871 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | |
| Investment income | | 48 |
| | — |
| | 21 |
| | (17 | ) | | 52 |
|
| Interest expense | | (259 | ) | | (42 | ) | | (144 | ) | | (51 | ) | | (496 | ) |
| Capitalized interest | | 3 |
| | 1 |
| | 22 |
| | 12 |
| | 38 |
|
| Total Other Expense | | (208 | ) | | (41 | ) | | (101 | ) | | (56 | ) | | (406 | ) |
| | | | | | | | | | | |
| Income Before Income Taxes | | 425 |
| | 127 |
| | 57 |
| | (144 | ) | | 465 |
|
| Income taxes | | 158 |
| | 47 |
| | 21 |
| | (1 | ) | | 225 |
|
| Net Income | | 267 |
| | 80 |
| | 36 |
| | (143 | ) | | 240 |
|
| Loss attributable to noncontrolling interest | | — |
| | — |
| | — |
| | (15 | ) | | (15 | ) |
| Earnings Available to FirstEnergy Corp. | | $ | 267 |
| | $ | 80 |
| | $ | 36 |
| | $ | (128 | ) | | $ | 255 |
|
|
| | | | | | | | | | | | | | | | | | | | |
Changes Between First Six Months 2012 and First Six Months 2011 Financial Results Increase (Decrease) | | Regulated Distribution | | Regulated Transmission | | Competitive
Energy Services | | Other and
Reconciling Adjustments | | FirstEnergy Consolidated |
| | | (In millions) |
| Revenues: | | | | | | | | | | |
| External | | | | | | | | | | |
| Electric | | $ | (198 | ) | | $ | — |
| | $ | 502 |
| | $ | 1 |
| | $ | 305 |
|
| Other | | (14 | ) | | 75 |
| | (16 | ) | | 3 |
| | 48 |
|
| Internal | | — |
| | — |
| | (184 | ) | | 142 |
| | (42 | ) |
| Total Revenues | | (212 | ) | | 75 |
| | 302 |
| | 146 |
| | 311 |
|
| | | | | | | | | | | |
| Operating Expenses: | | | | | | | | | | |
| Fuel | | — |
| | — |
| | 109 |
| | — |
| | 109 |
|
| Purchased power | | (346 | ) | | — |
| | 300 |
| | 143 |
| | 97 |
|
| Other operating expenses | | 75 |
| | 8 |
| | (334 | ) | | (81 | ) | | (332 | ) |
| Provision for depreciation | | 39 |
| | 16 |
| | 6 |
| | 4 |
| | 65 |
|
| Amortization of regulatory assets, net | | (77 | ) | | (5 | ) | | — |
| | (3 | ) | | (85 | ) |
| General taxes | | 3 |
| | 2 |
| | 15 |
| | 5 |
| | 25 |
|
| Total Operating Expenses | | (306 | ) | | 21 |
| | 96 |
| | 68 |
| | (121 | ) |
| | | | | | | | | | | |
| Operating Income | | 94 |
| | 54 |
| | 206 |
| | 78 |
| | 432 |
|
| | | | | | | | | | | |
| Other Income (Expense): | | | | | | | | | | |
| Investment income | | (6 | ) | | 1 |
| | (9 | ) | | (14 | ) | | (28 | ) |
| Interest expense | | (10 | ) | | (4 | ) | | 8 |
| | (18 | ) | | (24 | ) |
| Capitalized interest | | 2 |
| | — |
| | 1 |
| | (5 | ) | | (2 | ) |
| Total Other Expense | | (14 | ) | | (3 | ) | | — |
| | (37 | ) | | (54 | ) |
| | | | | | | | | | | |
| Income Before Income Taxes | | 80 |
| | 51 |
| | 206 |
| | 41 |
| | 378 |
|
| Income taxes | | 29 |
| | 19 |
| | 76 |
| | — |
| | 124 |
|
| Net Income | | 51 |
| | 32 |
| | 130 |
| | 41 |
| | 254 |
|
| Income attributable to noncontrolling interest | | — |
| | — |
| | — |
| | 16 |
| | 16 |
|
| Earnings Available to FirstEnergy Corp. | | $ | 51 |
| | $ | 32 |
| | $ | 130 |
| | $ | 25 |
| | $ | 238 |
|
Regulated Distribution — First Six Months of 20112012 Compared to First Six Months of 20102011
Net income increased by $45$51 million in the first six months of 2011,2012 compared to the first six monthssame period of 2010,2011, primarily due to the absence of a $35 million regulatory asset impairment recorded in 2010 and the earnings contribution offrom the Allegheny companies,Utilities and lower merger-related costs, partially offset by a favorable property tax settlement recognizeddecreased weather-related customer usage in 2010.the first six months of 2012.
Results of operations for the six months ended June 30, 2011, include only four months of Allegheny results which have been segregated from the pre-merger companies (FirstEnergy and its subsidiaries prior to the merger) for variance reporting and analysis.
Revenues —
The $212 milliondecrease in total revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Pre-merger companies: | | | | | | | | | | | | |
| Distribution services | | $ | 1,719 | | | $ | 1,733 | | | $ | (14 | ) |
| | | | | | | | | | |
| Generation sales: | | | | | | | | | | | | |
| Retail | | | 1,620 | | | | 2,272 | | | | (652 | ) |
| Wholesale | | | 220 | | | | 397 | | | | (177 | ) |
| | | | | | | | | | |
| Total generation sales | | | 1,840 | | | | 2,669 | | | | (829 | ) |
| | | | | | | | | | |
| Transmission | | | 88 | | | | 299 | | | | (211 | ) |
| Other | | | 123 | | | | 116 | | | | 7 | |
| | | | | | | | | | |
| Total pre-merger companies | | | 3,770 | | | | 4,817 | | | | (1,047 | ) |
| Allegheny companies | | | 983 | | | | — | | | | 983 | |
| | | | | | | | | | |
| Total Revenues | | $ | 4,753 | | | $ | 4,817 | | | $ | (64 | ) |
| | | | | | | | | | |
98
|
| | | | | | | | | | | | |
| | | Six Months Ended June 30 | | Increase |
| Revenues by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Pre-merger companies: | | | | | | |
| Distribution services | | $ | 1,541 |
| | $ | 1,721 |
| | $ | (180 | ) |
| Generation sales: | | | | | | |
| Retail | | 1,300 |
| | 1,620 |
| | (320 | ) |
| Wholesale | | 95 |
| | 220 |
| | (125 | ) |
| Total generation sales | | 1,395 |
| | 1,840 |
| | (445 | ) |
| Transmission | | 90 |
| | 11 |
| | 79 |
|
| Other | | 80 |
| | 93 |
| | (13 | ) |
| Total pre-merger companies | | 3,106 |
| | 3,665 |
| | (559 | ) |
Allegheny Utilities(1) | | 1,314 |
| | 967 |
| | 347 |
|
| Total Revenues | | $ | 4,420 |
| | $ | 4,632 |
| | $ | (212 | ) |
| |
(1) | Allegheny results include 6 months in 2012 and 4 months in 2011. |
The decrease in distribution service revenuesservices revenue for the pre-merger companies primarily reflects lower transition revenues duedistribution deliveries (described below), the suspension of Ohio's deferred distribution cost recovery rider in December 2011 and an NJBPU-approved reduction to the completion of transition cost recovery for CEI in December 2010,JCP&L NUG Rider which became effective on March 1, 2012, partially offset by increased rates associated witha PAPUC-approved increase to the recovery of deferred distribution costs.ME and PN NUG Rider which also became effective on March 1, 2012. Distribution deliveries (excluding the Allegheny companies) increased approximately 360,000 KWH (0.7%), primarily drivenUtilities) decreased by an increase of 443,000 KWH (2.6%)1.3% in the industrial class.first six months of 2012 from the same period of 2011. Distribution deliveries by customer class are summarized in the following table:
| | | | | | | | | | | | | |
| | | | | | | | | | | Increase | |
| Electric Distribution KWH Deliveries | | 2011 | | | 2010 | | | (Decrease) | |
| | | (in thousands) | | | | | |
| Pre-merger companies: | | | | | | | | | | | | |
| Residential | | | 19,261 | | | | 19,119 | | | | 0.7 | % |
| Commercial | | | 15,855 | | | | 16,074 | | | | (1.4 | )% |
| Industrial | | | 17,640 | | | | 17,197 | | | | 2.6 | % |
| Other | | | 256 | | | | 262 | | | | (2.3 | )% |
| | | | | | | | | | |
| Total pre-merger companies | | | 53,012 | | | | 52,652 | | | | 0.7 | % |
| | | | | | | | | | |
| Allegheny companies | | | 13,068 | | | | — | | | | — | |
| | | | | | | | | | |
| Total Electric Distribution KWH Deliveries | | | 66,080 | | | | 52,652 | | | | 25.5 | % |
| | | | | | | | | | |
|
| | | | | | | | | |
| | | Six Months Ended June 30 | | Increase |
| Electric Distribution MWH Deliveries | | 2012 | | 2011 | | (Decrease) |
| | | (In thousands) | | |
| Pre-merger companies: | | | | | | |
| Residential | | 18,294 |
| | 19,288 |
| | (5.2 | )% |
| Commercial | | 15,777 |
| | 15,882 |
| | (0.7 | )% |
| Industrial | | 18,071 |
| | 17,640 |
| | 2.4 | % |
| Other | | 248 |
| | 256 |
| | (3.1 | )% |
| Total pre-merger companies | | 52,390 |
| | 53,066 |
| | (1.3 | )% |
Allegheny Utilities(1) | | 20,137 |
| | 13,068 |
| | 54.1 | % |
| Total Electric Distribution MWH Deliveries | | 72,527 |
| | 66,134 |
| | 9.7 | % |
| |
(1) | Allegheny results include 6 months in 2012 and 4 months in 2011. |
Lower distribution deliveries to residential and commercial customers reflected soft economic conditions in this sector andfor the pre-merger companies reflect decreased weather-related usage in the first six months ofresulting from heating degree days that were 21% below 2011 aslevels, partially offset by cooling degree days that were 17% below9% higher than 2011 levels. In the same period in 2010. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in the Utilities’ service territory compared to the first six months of 2010. Industrialsector, MWH deliveries increased by 12%3% to steel customers 16%and 3% to electrical equipment and component manufacturing customers and 10% to non-metallic mineralautomotive customers, partially offset by a decrease of 1% to petroleum customers and 2% lower sales to automotivechemical customers.
The following table summarizes the price and volume factors contributing to the $829$445 milliondecrease in generation revenues for the pre-merger companies in the first six months of 20112012 compared to the same period of 2010:2011:
| | | | | |
| | | Increase | |
| Source of Change in Generation Revenues | | (Decrease) | |
| | | (In millions) | |
| Retail: | | | | |
| Effect of decrease in sales volumes | | $ | (826 | ) |
| Change in prices | | | 174 | |
| | | | |
| | | | (652 | ) |
| | | | |
| Wholesale: | | | | |
| Effect of decrease in sales volumes | | | (2 | ) |
| Change in prices | | | (175 | ) |
| | | | |
| | | | (177 | ) |
| | | | |
| Net Decrease in Generation Revenues | | $ | (829 | ) |
| | | | |
|
| | | | |
| Source of Change in Generation Revenues | | Increase (Decrease) |
| | | (In millions) |
| Retail: | | |
| Effect of decrease in sales volumes | | $ | (328 | ) |
| Change in prices | | 8 |
|
| | | (320 | ) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | (87 | ) |
| Change in prices | | (38 | ) |
| | | (125 | ) |
| Net Decrease in Generation Revenues | | $ | (445 | ) |
The decrease in retail generation sales volume was primarily due to increased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’sUtilities' service territories in the first six months of 20112012, compared towith the same period in 2010.of 2011. Total generation provided by alternative suppliers as a percentage of total KWHMWH deliveries increased to 75%78% from 57%75% for the Ohio companiesCompanies, 63% from 48% for ME's, PN's and to 48%Penn's service areas and 50% from 9%43% for Met-Ed’s and Penelec’s service areas. JCP&L.
The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelecof $125 million in the first six months of 2012 was a result of the expiration of a NUG contract in August 2011 and lower PJM market.market prices.
Transmission revenues increased $79 million primarily due tothe implementation of Ohio's NMB transmission rider in June of 2011, which recovers network integration transmission service charges as described further below.
Operating Expenses —
Total operating expenses decreased $211by $306 million due to the termination of Met-Ed’s and Penelec’s TSC rates 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.following:
The Allegheny companies added $983 million of revenues for the first six months of 2011, including $216 million for distribution services, $676 million from generation sales and $91 million relating to transmission revenues.
99
Expenses —
Total expenses decreased by $160 million due to the following:
Purchased power costs, excluding the Allegheny companies,Utilities, were $843$526 million lower in the first six months of 2012 due primarily to a decrease in volumes required from increased customer shopping and the impact of milder weather.
|
| | | | | |
| | Source of Change in Purchased Power | | Increase (Decrease) |
| |
| | | | (In millions) |
| | Pre-merger companies: | | |
| | Purchases from non-affiliates: | | |
| | Change due to decreased unit costs | | $ | (83 | ) |
| | Change due to decreased volumes | | (300 | ) |
| | | | (383 | ) |
| | Purchases from FES: | | |
| | Change due to decreased unit costs | | (27 | ) |
| | Change due to decreased volumes | | (167 | ) |
| | | | (194 | ) |
| | Decrease in costs deferred | | 51 |
|
| | Total pre-merger companies | | (526 | ) |
| | Purchases by Allegheny Utilities | | 180 |
|
| | Net Decrease in Purchased Power Costs | | $ | (346 | ) |
Transmission expenses increased $96 million during the first six months of 2012 compared to the same period of 2011. The increase is primarily due to network integration transmission service expenses that, prior to June 2011, were incurred by the generation supplier, and are now being recovered through the NMB transmission rider referred to above.
Regulatory assets amortization expense decreased $85 million due to the following:
| |
| ◦ | The scheduled suspension of the rider recovering deferred distribution costs in December 2011, |
| |
| ◦ | The completion of JCP&L's NUG deferred cost recovery, |
| |
| ◦ | Partially offset by the recovery in Ohio of residential generation credits for electric heating discounts, which began in September 2011. |
Energy Efficiency program costs, which are recovered through rates, increased by $24 million.
General taxes decreased by $17 million primarily due to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described abovegross receipts taxes for ME, PN and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offsetJCP&L.
Depreciation expense increased by a decrease in RPM expenses in the PJM market. The Allegheny companies added $481 million in purchased power costs in the first six months of 2011.
| | | | | |
| | | Increase | |
| Source of Change in Purchased Power | | (Decrease) | |
| | | (In millions) | |
| Pre-merger companies: | | | | |
| Purchases from non-affiliates: | | | | |
| Change due to decreased unit costs | | $ | (356 | ) |
| Change due to increased volumes | | | 277 | |
| | | | |
| | | | (79 | ) |
| | | | |
| Purchases from FES: | | | | |
| Change due to increased unit costs | | | 63 | |
| Change due to decreased volumes | | | (809 | ) |
| | | | |
| | | | (746 | ) |
| | | | |
| | | | | |
| Increase in costs deferred | | | (18 | ) |
| | | | |
| Total pre-merger companies | | | (843 | ) |
| | | | |
| Purchases by Allegheny companies | | | 481 | |
| | | | |
| Net Decrease in Purchased Power Costs | | $ | (362 | ) |
| | | | |
Transmission expenses decreased $124$11 million primarily due to lower PJM network transmission expenses and congestion costs of $177 million for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies of $53 million in the first six months of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmissionhigher asset removal costs incurred with no material effect on earnings.
by JCP&L.Energy efficiency programOther costs which are also recovered through rates, increased $62 million.
Thedecreased due to the absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.
A provision for excess and obsolete material of $13 million that was recognized in the first six monthsquarter of 2011 duerelating to revised inventory practices adopted in conjunction with the Allegheny merger.
Net amortization of regulatory assetsMerger-related costs decreased $150 million primarily due to reduced net PJM transmission cost and transition cost recovery and the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio ESP on March 23, 2010, partially offset by increased energy efficiency cost recovery.
Fuel expenses for MP were $97$54 million in the first six months of 2011.
Operating expenses for the Allegheny companies were $131 million in the first six months of 2011.
Merger-related costs increased $46 million in the first six months of 20112012 compared to the same period of 2010.2011.
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
Operating Expenses - Allegheny(1) | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) | | |
| Purchased Power | | $ | 653 |
| | $ | 473 |
| | $ | 180 |
|
| Fuel | | 97 |
| | 97 |
| | — |
|
| Transmission | | 68 |
| | 51 |
| | 17 |
|
| Amortization of regulatory assets, net | | (5 | ) | | (13 | ) | | 8 |
|
| Other operating expenses | | 24 |
| | 8 |
| | 16 |
|
| General Taxes | | 68 |
| | 48 |
| | 20 |
|
| Depreciation Expense | | 85 |
| | 57 |
| | 28 |
|
| Total Operating Expenses | | $ | 990 |
| | $ | 721 |
| | $ | 269 |
|
| |
(1) | Allegheny results include 6 months in 2012 and 4 month in 2011. |
Other Expense —
Other expense forincreased $14 million in the Allegheny companies was $64 million.
General taxes increased by $64 millionfirst six months of 2012 primarily due to taxes incurred by the Allegheny companies and the absence of a favorable property tax settlement recognized in 2010.
Other Expense —
Other expense increased by $30 million in the first six months of 2011 due tonet interest expense on debt of the Allegheny companies.Utilities.
Regulated Independent Transmission — First Six Months 2011 of 2012 Compared with First Six Months 2010 of 2011
Net income increased by $21$32 million in the first six months of 20112012 compared to the first six monthssame period of 20102011 primarily due to earnings associated with TrAIL, PATH and PATH ($27 million), partially offset by decreased earnings for ATSI ($6 million).the Allegheny Utilities' transmission assets that were acquired in the merger.
100
Revenues —
Total revenues increased by $75 million principally due to revenues from TrAIL, PATH and the Allegheny Utilities' transmission assets.
Revenues by transmission asset owner are shown in the following table:
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| Revenues by | | Ended June 30 | | | Increase | |
| Transmission Asset Owner | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| ATSI | | $ | 106 | | | $ | 116 | | | $ | (10 | ) |
| TrAIL | | | 61 | | | | — | | | | 61 | |
| PATH | | | 5 | | | | — | | | | 5 | |
| | | | | | | | | | |
| Total Revenues | | $ | 172 | | | $ | 116 | | | $ | 56 | |
| | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| Revenues by Transmission Asset Owner | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| ATSI | | $ | 107 |
| | $ | 106 |
| | $ | 1 |
|
TrAIL(1) | | 102 |
| | 61 |
| | 41 |
|
PATH(1) | | 7 |
| | 5 |
| | 2 |
|
Utilities(1) | | 154 |
| | 123 |
| | 31 |
|
| Total Revenues | | $ | 370 |
| | $ | 295 |
| | $ | 75 |
|
| |
(1) | Allegheny results include 6 months in 2012 and 4 months in 2011. |
Operating Expenses —
Total operating expenses increased by $14$21 million principally due to the addition of TrAIL, PATH and PATHthe Allegheny Utilities' transmission operating expenses.expenses for six months in 2012 compared to four months in 2011, partially offset by reduced regulatory asset amortization expense due to the completion in May 2011 of ATSI's deferred vegetation management cost recovery.
Other Expense —
Other expense increased $10by $3 million in the first six months of 2012 due to a full six months of 2011 due toTrAIL interest expense associated with TrAIL.compared to four months in 2011.
Competitive Energy Services — First Six Months of 20112012 Compared to with First Six Months of 20102011
Net income decreasedincreased by $173$130 million in the first six months of 2011,2012, compared to the first six monthssame period of 2010, primarily2011, due to lower sales margin, an inventory reserve adjustment, non-core asset impairmentshigher retail revenues and the effectinclusion of mark-to-market adjustments.the results of the Allegheny companies, partially offset by higher operating expenses.
Revenues —
Total revenues increased $670by $302 million in the first six months of 20112012 primarily due to growth in direct and governmental aggregation and wholesale sales and the inclusion of the Allegheny companies for six months in 2012 compared to four months in 2011, partially offset by a net decline in POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the first six months of 2011.
The increase in total revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Direct and Governmental Aggregation | | $ | 1,765 | | | $ | 1,097 | | | $ | 668 | |
| POLR and Structured Sales | | | 607 | | | | 1,315 | | | | (708 | ) |
| Wholesale | | | 156 | | | | 142 | | | | 14 | |
| Transmission | | | 56 | | | | 36 | | | | 20 | |
| RECs | | | 44 | | | | 67 | | | | (23 | ) |
| Other | | | 79 | | | | 70 | | | | 9 | |
| Allegheny Companies | | | 690 | | | | — | | | | 690 | |
| | | | | | | | | | |
Total Revenues | | $ | 3,397 | | | $ | 2,727 | | | $ | 670 | |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct and Governmental Aggregation | | $ | 34 | | | | | | | | | |
| POLR and Structured Sales | | | 254 | | | | | | | | | |
| Wholesale | | | 357 | | | | | | | | | |
| Transmission | | | 44 | | | �� | | | | | | |
| Other | | | 1 | | | | | | | | | |
| | | | | | | | | | | | |
Total Revenues | | $ | 690 | | | | | | | | | |
| | | | | | | | | | | | |
101
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| Revenues by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Pre-merger Companies: | | | | | | |
| Direct and Governmental Aggregation | | $ | 2,040 |
| | $ | 1,765 |
| | $ | 275 |
|
| POLR and Structured Sales | | 426 |
| | 607 |
| | (181 | ) |
Wholesale(1) | | 259 |
| | 156 |
| | 103 |
|
| Transmission | | 60 |
| | 56 |
| | 4 |
|
| RECs | | 5 |
| | 44 |
| | (39 | ) |
| Other | | 76 |
| | 79 |
| | (3 | ) |
Allegheny companies(2) | | 833 |
| | 690 |
| | 143 |
|
| Total Revenues | | $ | 3,699 |
| | $ | 3,397 |
| | $ | 302 |
|
| | | | | | | |
Allegheny companies(2) | | | | | | |
| Direct and Governmental Aggregation | | $ | 46 |
| | $ | 34 |
| | $ | 12 |
|
| POLR and Structured Sales | | 248 |
| | 254 |
| | (6 | ) |
| Wholesale | | 511 |
| | 357 |
| | 154 |
|
| Transmission | | 28 |
| | 44 |
| | (16 | ) |
| Other | | — |
| | 1 |
| | (1 | ) |
| Total Revenues | | $ | 833 |
| | $ | 690 |
| | $ | 143 |
|
| | | | | | | |
(1) Excludes $128 million in intra-segment sales by AE Supply to FES |
(2) Allegheny results include 6 months in 2012 and 4 months in 2011. |
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| MWH Sales by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In thousands) | | | | | |
| Direct | | | 21,219 | | | | 12,857 | | | | 65.0 | % |
| Governmental Aggregation | | | 8,279 | | | | 5,447 | | | | 52.0 | % |
| POLR and Structured Sales | | | 9,561 | | | | 25,344 | | | | (62.3 | )% |
| Wholesale | | | 1,380 | | | | 1,538 | | | | (10.3 | )% |
| Allegheny Companies | | | 10,687 | | | | — | | | | — | |
| | | | | | | | | | |
Total Sales | | | 51,126 | | | | 45,186 | | | | 13.1 | % |
| | | | | | | | | | |
| | | | | | | | | | | | | |
Allegheny Companies | | | | | | | | | | | | |
| Direct | | | 570 | | | | | | | | | |
| POLR | | | 2,981 | | | | | | | | | |
| Structured Sales | | | 1,149 | | | | | | | | | |
| Wholesale | | | 5,987 | | | | | | | | | |
| | | | | | | | | | | | |
Total Sales | | | 10,687 | | | | | | | | | |
| | | | | | | | | | | | |
79
|
| | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| MWH Sales by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In thousands) | | |
| Pre-merger Companies: | | | | | | |
| Direct | | 25,954 |
| | 21,219 |
| | 22.3 | % |
| Governmental Aggregation | | 9,930 |
| | 8,279 |
| | 19.9 | % |
| POLR and Structured Sales | | 7,645 |
| | 9,561 |
| | (20.0 | )% |
| Wholesale | | 86 |
| | 1,380 |
| | (93.8 | )% |
Allegheny companies(1) | | 13,406 |
| | 10,687 |
| | 25.4 | % |
| Total MWH Sales | | 57,021 |
| | 51,126 |
| | 11.5 | % |
| | | | | | | |
Allegheny companies(1) | | | | | | |
| Direct and Governmental Aggregation | | 762 |
| | 570 |
| | 33.7 | % |
| POLR | | 4,098 |
| | 2,981 |
| | 37.5 | % |
| Structured Sales | | 279 |
| | 1,149 |
| | (75.7 | )% |
| Wholesale | | 8,267 |
| | 5,987 |
| | 38.1 | % |
| Total MWH Sales | | 13,406 |
| | 10,687 |
| | 25.4 | % |
| | | | | | | |
(1) Allegheny results include 6 months in 2012 and 4 months in 2011. |
The increase in combined direct and governmental aggregation revenues of $668$275 million resulted from increased revenue from the acquisition of new residential, commercial and industrial customers. Our customer base increased to 2.0 million industrial, commercial and residential customers as wellof June 2012 as newcompared to 1.7 million in June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation contracts with communities in Ohio that provided generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million customers at the end of June 2010.customers.
The decrease in combined POLR and structured revenues of $708$181 million was due primarily to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, ME and PN. Revenues were also adversely impacted by lower unit prices, discussed above, which were partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participationstructured sales. The decline in POLR auctions and RFPs are expected to continue but the proportion of these sales will dependreflects a continued focus on our hedge positions for our direct retail and aggregation sales.other sales channels.
Wholesale revenues increased by $14$103 million due to higher wholesale pricesincreased gains of $100 million on financially settled contracts and a $42 million increase in capacity revenues. These increases were partially offset by decreased volumes. The lower sales volumes were the resultsold of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by units moved to PJM were partially offset by losses on financially settled sales.$39 million.
The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):
| | | | | |
| | | Increase | |
| Source of Change in Direct and Governmental Aggregation | | (Decrease) | |
| | | (In millions) | |
| Direct Sales: | | | | |
| Effect of increase in sales volumes | | $ | 493 | |
| Change in prices | | | (20 | ) |
| | | | |
| | | | 473 | |
| | | | |
| Governmental Aggregation: | | | | |
| Effect of increase in sales volumes | | | 176 | |
| Change in prices | | | 19 | |
| | | | |
| | | | 195 | |
| | | | |
| Net Increase in Direct and Governmental Aggregation Revenues | | $ | 668 | |
| | | | |
102
|
| | | | |
| Source of Change in Direct and Governmental Aggregation | | Increase (Decrease) |
| | | (In millions) |
| Direct and Governmental Aggregation: | | |
| Effect of increase in sales volumes | | $ | 381 |
|
| Change in prices | | (106 | ) |
| | | $ | 275 |
|
| | | | | |
| | | Increase | |
| Source of Change in POLR Revenues | | (Decrease) | |
| | | (In millions) | |
| POLR: | | | | |
| Effect of decrease in sales volumes | | $ | (819 | ) |
| Change in prices | | | 111 | |
| | | | |
| | | | (708 | ) |
| | | | |
| | | | |
| | Increase | |
Source of Change in Wholesale Revenues | | (Decrease) | |
Wholesale: | | | | |
Effect of decrease in sales volumes | | | (15 | ) |
Change in prices | | | 29 | |
| | | |
| | | 14 | |
| | | |
|
| | | | |
| Source of Change in POLR and Structured Revenues | | Increase (Decrease) |
| | | (In millions) |
| POLR and Structured: | | |
| Effect of decrease in sales volumes | | $ | (122 | ) |
| Change in prices | | (59 | ) |
| | | $ | (181 | ) |
|
| | | | |
| Source of Change in Wholesale Revenues | | Increase (Decrease) |
| | | (In millions) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | $ | (39 | ) |
| Change in prices | | — |
|
| Gain on settled contracts | | 100 |
|
| Capacity revenue | | 42 |
|
| | | $ | 103 |
|
Operating Expenses —
Total operating expenses for the pre-merger companies increased by $20$95 million in the first six months of 2012 due to the following:
Fuel costs increased $38 million primarily due to higher unit prices ($29 million) and higher volumes consumed ($9 million). Volumes increased due to higher nuclear generation, partially offset by lower generation from the fossil units.
Purchased power costs increased $295 million due to higher volumes ($147 million), loss on settled contracts ($229 million) and increased capacity expense ($61 million), partially offset by lower unit prices ($142 million). The increase in purchased power volumes primarily relates to the overall increase in direct and governmental aggregation sales volumes and economic purchases.
Fossil operating costs decreased by $16 million due primarily to higher MISOlower contractor, materials and PJM congestion revenue. The revenues derivedequipment costs resulting from a decrease in planned and unplanned outages, partially offset by severance costs associated with certain fossil units to be deactivated.
Nuclear operating costs decreased by $8 million due primarily to lower labor, materials and equipment costs. During the salefirst six months of RECs declined $23 million2012, there were refueling outages at Davis Besse and Beaver Valley Unit 1 compared to 2011, which included refueling outages at Perry and Beaver Valley Unit 2. Total outage days were reduced in the first six months of 2011.
Expenses —
Total expenses increased by $901 million in the first six months of 2011 due2012 compared to the following:same period of 2011.
Fuel costsTransmission expenses decreased by $13 million primarily due to decreased volumes ($28 million), partially offset by higher unit prices ($15 million). Volumes decreased due to lower generation from the fossil units. Unit prices increased primarily due to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.
Purchased power costs decreased by $154$89 million due primarily to lower volumes purchased ($248 million) partially offset by higher unit costs ($94 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.
Fossil operating costs increased by $20 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.
Nuclear operating costs increased by $48 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.
Transmission expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network and line loss expense,costs, partially offset by lower MISO transmission expenses of $22 million.higher ancillary costs.
General taxes increased by $12$4 million primarily due to an increase in revenue-related taxes.
Other expenses increased by $93Depreciation expense decreased $15 million primarily due to:to a lower asset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain fossil assets and credits resulting from a settlement with the DOE regarding storage of spent nuclear fuel.
Other operating expenses decreased by $114 million primarily due to favorable mark-to-market adjustments on commodity contract positions ($64 million) and reduced costs associated with the merger ($14 million). In addition, 2011 expenses included a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger;merger and a $20 million impairment charge related to non-core assets;assets. These decreases were partially offset by increases in other expenses of $38 million associated with inter-segment leases, and a $9 million increase in intercompany billings. The intercompany billings increased due to merger relatedlabor, agent fees and professional and contractor costs and increased intersegment billings for leasehold costs from the Ohio Companies.associated with our retail business.
103
The inclusion of the Allegheny companies’ operations contributed $719for six months in 2012 and four months in 2011 added $720 million and $719 million to operating expenses, including a $43 million mark-to-market adjustment relating primarily to power contracts.respectively, as shown in the following table:
| | | | | |
| | | Increase | |
| Source of Expense Changes | | (Decrease) | |
| | | (In millions) | |
Allegheny Companies | | | | |
| Fuel | | $ | 320 | |
| Purchased power | | | 74 | |
| Fossil | | | 82 | |
| Transmission | | | 99 | |
| Mark-to-Market | | | 43 | |
| General taxes | | | 15 | |
| Other | | | 43 | |
| Depreciation | | | 43 | |
| | | | |
| Total Expense | | $ | 719 | |
| | | | |
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
Operating Expenses (Credits) - Allegheny(1) | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Fuel | | $ | 391 |
| | $ | 320 |
| | $ | 71 |
|
| Purchased power | | 79 |
| | 74 |
| | 5 |
|
| Fossil generation | | 88 |
| | 82 |
| | 6 |
|
| Transmission | | 63 |
| | 99 |
| | (36 | ) |
| Other operating expenses | | 23 |
| | 43 |
| | (20 | ) |
| Mark-to-market adjustments | | (16 | ) | | 43 |
| | (59 | ) |
| General taxes | | 28 |
| | 15 |
| | 13 |
|
| Depreciation | | 64 |
| | 43 |
| | 21 |
|
| Total Operating Expense | | $ | 720 |
| | $ | 719 |
| | $ | 1 |
|
| | | | | | | |
(1) Allegheny results include 6 months in 2012 and 4 months in 2011. |
Other Expense —
Total other expense in the first six months of 20112012 was $49 million higher thanflat compared to the first six months of 2010, primarily due to a $56 million increase in2011. Reduced net interest expense partiallyfrom debt reductions in 2011 was offset by an increase inlower investment income from the nuclear decommissioning trust investment income ($7 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($30 million) and lower capitalized interest ($25 million) associated with the completion of the Sammis AQC project in 2010.trusts.
Other — First Six Months of 20112012 Compared to with First Six Months of 20102011
Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in an $82a $25 million decreaseincrease in earnings available to FirstEnergy Corp. in the first six months of 20112012 compared to the same period in 2010.of 2011. The decreaseincrease resulted primarily from increaseddecreased other operating expenses resulting from adverse litigation resolution ($2981 million) due to lower merger-related costs, partially offset by increased net interest expenses ($23 million), decreased capitalizedinvestment income ($14 million) and decreased income attributable to noncontrolling interest and increased depreciation expense resulting from completed construction projects placed into service ($27 million), an asset impairment charge($16 million) relating to Global Holding, which was de-consolidated in the firstfourth quarter of 2011 ($12 million) and increased income taxes ($9 million).2011.
Regulatory Assets
FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatoryRegulatory 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 June 30, 2011 and December 31, 2010 and changes during the six months then ended:
| | | | | | | | | | | | | |
| | | June 30, | | | December 31, | | | Increase | |
| Regulatory Assets | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| OE | | $ | 393 | | | $ | 400 | | | $ | (7 | ) |
| CEI | | | 320 | | | | 370 | | | | (50 | ) |
| TE | | | 89 | | | | 72 | | | | 17 | |
| JCP&L | | | 469 | | | | 513 | | | | (44 | ) |
| Met-Ed | | | 341 | | | | 296 | | | | 45 | |
| Penelec | | | 222 | | | | 163 | | | | 59 | |
| Other* | | | 348 | | | | 12 | | | | 336 | |
| | | | | | | | | | |
| Total | | $ | 2,182 | | | $ | 1,826 | | | $ | 356 | |
| | | | | | | | | | |
| | |
* | | 2011 includes $337 million related to the Allegheny companies. |
104
The following tables provide information about the composition of net regulatory assets as of June 30, 20112012 and December 31, 20102011, and the changes during the six months then ended:ended June 30, 2012:
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | Amount of | |
| | | | | | | | | | | | | | | Increase | |
| | | | | | | | | | | | | | | (Decrease) | |
| | | June 30, | | | December 31, | | | Increase | | | Attributable | |
| Regulatory Assets by Source | | 2011 | | | 2010 | | | (Decrease) | | | to AE | |
| | | (In millions) | | | | | |
| Regulatory transition costs | | $ | 899 | | | $ | 770 | | | $ | 129 | | | $ | — | |
| Customer receivables for future income taxes | | | 502 | | | | 326 | | | | 176 | | | | 160 | |
| Loss on reacquired debt | | | 53 | | | | 48 | | | | 5 | | | | 8 | |
| Employee postretirement benefits | | | 11 | | | | 16 | | | | (5 | ) | | | — | |
| Nuclear decommissioning and spent fuel disposal costs | | | (201 | ) | | | (184 | ) | | | (17 | ) | | | — | |
| Asset removal costs | | | (228 | ) | | | (237 | ) | | | 9 | | | | 22 | |
| MISO/PJM transmission costs | | | 292 | | | | 184 | | | | 108 | | | | 76 | |
| Deferred generation costs | | | 454 | | | | 386 | | | | 68 | | | | 15 | |
| Distribution costs | | | 284 | | | | 426 | | | | (142 | ) | | | — | |
| Other | | | 116 | | | | 91 | | | | 25 | | | | 56 | |
| | | | | | | | | | | | | |
| Total | | $ | 2,182 | | | $ | 1,826 | | | $ | 356 | | | $ | 337 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| Regulatory Assets by Source | | June 30,
2012 | | December 31,
2011 | | Increase (Decrease) |
| | | (In millions) |
| Regulatory transition costs | | $ | 297 |
| | $ | 309 |
| | $ | (12 | ) |
| Customer receivables for future income taxes | | 490 |
| | 519 |
| | (29 | ) |
| Nuclear decommissioning and spent fuel disposal costs | | (215 | ) | | (210 | ) | | (5 | ) |
| Asset removal costs | | (375 | ) | | (347 | ) | | (28 | ) |
| Deferred transmission costs | | 392 |
| | 340 |
| | 52 |
|
| Deferred generation costs | | 334 |
| | 400 |
| | (66 | ) |
| Deferred distribution costs | | 249 |
| | 267 |
| | (18 | ) |
| Contract valuations | | 516 |
| | 299 |
| | 217 |
|
| Other | | 434 |
| | 453 |
| | (19 | ) |
| Total | | $ | 2,122 |
| | $ | 2,030 |
| | $ | 92 |
|
FirstEnergy had $385$437 million of net regulatory liabilities as of June 30, 2011, including $376 million of net regulatory liabilities acquired as part of the merger with AE2012, that are primarily related to customer receivables for future income taxes and asset removal costs.
Regulatory assets that do not earn a current return totaled approximately $345$315 million as of June 30, 2011,2012. JCP&L had $118 million of which $138 million relates to purchase accounting fair value adjustments to corresponding liabilities that do not accrue interest.
Regulatoryregulatory assets not earning a current return, for Met-Ed and Penelec include certain regulatory transition costs and PJM transmission costs of approximately $144 million and $34 million, respectively. The regulatory transition costs are expected to be recovered by 2020.
Regulatory assets not earning a current return for JCP&Lwhich include certain storm damage costs and pension and postretirementOPEB benefits of approximately $34 million that are expected to be recovered by 2014.
Regulatory2026. The remaining $197 million of regulatory assets not earning a current return for FirstEnergy’s other utility subsidiaries include certain deferred generationPJM transmission and other
regulatory transition costs, of approximately $133 million thatwhich are expected to be recovered though 2026.by 2020.
CAPITAL RESOURCES AND LIQUIDITY
As of June 30, 2011,2012, FirstEnergy had $476$94 million of cash and cash equivalents and available to fund investments, operations and capital expenditures. In addition to internal sources to fund liquidity and capital requirements for 2011 and beyond, FirstEnergy may rely on 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.
approximately $3.6 billion. FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for the remainder of 2012 and beyond, FirstEnergy expects to rely on 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 the issuance of long-term debt and/or equity. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.
A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital resource requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate 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.
105
As of June 30, 2011,2012, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to the classification of certain variable interest rate PCRBs as currently payable long-term debt, and short-term borrowings. Currently payable long-term debtwhich, as of June 30, 2011,2012, included the following (in millions):following:
| | | | | |
| Currently Payable Long-term Debt | | | | |
PCRBs supported by bank LOCs (1) | | $ | 949 | |
| AE Supply unsecured note | | | 503 | |
| FirstEnergy Corp. unsecured note | | | 250 | |
FGCO and NGC unsecured PCRBs (1) | | | 136 | |
| WP unsecured note | | | 80 | |
| NGC collateralized lease obligation bonds | | | 59 | |
| Sinking fund requirements | | | 50 | |
| Other notes | | | 31 | |
| | | | |
| | | $ | 2,058 | |
| | | | |
|
| | | |
| Currently Payable Long-term Debt | (In millions) |
PCRBs supported by bank LOCs (1) | $ | 713 |
|
| Term loan | 150 |
|
| Unsecured notes | 150 |
|
Unsecured PCRBs (1) | 317 |
|
Secured PCRBs (1) | 106 |
|
| Collateralized lease obligation bonds | 71 |
|
| Sinking fund requirements | 54 |
|
| Other notes | 16 |
|
| | $ | 1,577 |
|
| | |
(1) | | InterestThese PCRBs are classified as currently payable long-term debt because the applicable interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. |
Credit FacilityShort-Term Borrowings and Liquidity
FirstEnergy had approximately $656 million and $700 million$1.9 billion of short-term borrowings as of June 30, 20112012, and no significant short-term borrowings as of December 31, 2010, respectively.2011. FirstEnergy’s available liquidity as of July 29, 2011,June 30, 2012, is summarized in the following table:
| | | | | | | | | | | | | | | |
| | | | | | | | | | | | | Available | |
| Company | | Type | | Maturity | | Commitment | | | Liquidity | |
| | | | | | | | (In millions) | |
FirstEnergy(1) | | Revolving | | June 2016 | | $ | 2,000 | | | $ | 1,751 | |
| FES / AE Supply | | Revolving | | June 2016 | | | 2,500 | | | | 2,449 | |
| TrAIL | | Revolving | | Jan. 2013 | | | 450 | | | | 450 | |
| AGC | | Revolving | | Dec. 2013 | | | 50 | | | | — | |
| | | | | | | | | | | | | |
| | | | | Subtotal | | $ | 5,000 | | | $ | 4,650 | |
| | | | | Cash | | | — | | | | 586 | |
| | | | | | | | | | | | | |
| | | | | Total | | $ | 5,000 | | | $ | 5,236 | |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| Company | | Type | | Maturity | | Commitment | | Available Liquidity |
| | | | | | | (In millions) |
FirstEnergy(1) | | Revolving | | May 2017 | | $ | 2,000 |
| | $ | 1,080 |
|
| FES / AE Supply | | Revolving | | May 2017 | | 2,500 |
| | 2,498 |
|
FET(2) | | Revolving | | May 2017 | | 1,000 |
| | — |
|
| AGC | | Revolving | | Dec 2013 | | 50 |
| | — |
|
| | | | | Subtotal | | $ | 5,550 |
| | $ | 3,578 |
|
| | | | | Cash | | — |
| | 63 |
|
| | | | | Total | | $ | 5,550 |
| | $ | 3,641 |
|
| | |
(1) | | FirstEnergy Corp. and regulated subsidiary borrowers.the Utilities. |
| |
(2) | Includes FET, ATSI and TrAIL. |
During March 2011, the accounts receivable financing arrangements for OE, TE, Penelec and Met-Ed were terminated in favor of other sources of liquidity that were deemed more economical. In May 2011, AE terminated its $250 million credit facility. AE now participates in the unregulated money pool (see FirstEnergy Money Pools below).
Revolving Credit Facilities
On June 17, 2011, FirstEnergy, FES/AE Supply and FET Facilities
FE and certain of its subsidiaries entered into two newparticipate in three five-year syndicated revolving credit facilities with aggregate commitments of $4.5$5.5 billion (New Facilities)(Facilities).
An aggregate amount The Facilities consist of $2a $2.0 billion is available to be borrowed under a syndicated revolving credit facility (New FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the New aggregate FirstEnergy Facility, are FirstEnergy, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec, PE and WP. An additional $2.5a $2.5 billion is available to be borrowed by FES and FES/AE Supply under a separate syndicated revolving credit facility (New FES/AESupply Facility).
The New Facilities replaced a FirstEnergy $2.75 billion revolving credit facility, an AE Supply $1 billion revolving credit facility, a MP $110 million revolving credit facility, a PE $150 million revolving credit facilityFacility and a WP $200 million revolving credit facility, all of which were terminated as of June 17, 2011. Initial borrowings under the New Facilities were used to pay off outstanding obligations under these prior revolving credit facilities.
Commitments under$1.0 billion FET Facility, that are each of the New Facilities will be available until June 17, 2016,May 2017, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the New Facilities are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended.
Borrowings under each Each of the New Facilities are subject to acceleration upon the occurrence of events of default thatcontains financial covenants requiring each borrower considers usualto maintain a consolidated debt to total capitalization ratio of no more than 65%, and customary, including a cross-default70% for other indebtedness in excessFET, measured at the end of $100 million. Defaults by either FES or AE Supply or their respective subsidiaries under the New FES/AESupply Facility or other indebtedness generally will not cross-default to FirstEnergy under the New FirstEnergy Facility.each fiscal quarter.
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The following table summarizes the borrowing sub-limits for each borrower under the facilities, as well asFacilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations, as well as the debt to total capitalization ratios (as defined under each of the Facilities) as of June 30, 2011:2012:
| | | | | | | | | |
| | | New Revolving | | | Regulatory and | |
| | | Credit Facility | | | Other Short-Term | |
| Borrower | | Sub-Limit | | | Debt Limitations | |
| | | (In millions) | |
| FirstEnergy | | $ | 2,000 | | | | — | (a) |
| FES | | $ | 1,500 | | | | — | (b) |
| AE Supply | | $ | 1,000 | | | | — | (b) |
| OE | | $ | 500 | | | $ | 500 | |
| CEI | | $ | 500 | | | $ | 500 | |
| TE | | $ | 500 | | | $ | 500 | |
| JCP&L | | $ | 425 | | | $ | 411 | (c) |
| Met-Ed | | $ | 300 | | | $ | 300 | (c) |
| Penelec | | $ | 300 | | | $ | 300 | (c) |
| West Penn | | $ | 200 | | | $ | 200 | (c) |
| MP | | $ | 150 | | | $ | 150 | (c) |
| PE | | $ | 150 | | | $ | 150 | (c) |
| ATSI | | $ | 100 | | | $ | 100 | |
| Penn | | $ | 50 | | | $ | 33 | (c) |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Borrower | | FirstEnergy Revolving Credit Facility Sub-Limit | | FES/AE Supply Revolving Credit Facility Sub-Limit | | FET Revolving Credit Facility Sub-Limit | | Regulatory and Other Short-Term Debt Limitations | | | Debt to Capitalization |
| | | (In millions) | | | |
| FE | | | $ | 2,000 |
| | | $ | — |
| | | $ | — |
| | | $ | — |
| (2) | | 58.8% |
| FES | | | — |
| | | 1,500 |
| | | — |
| | | — |
| (3) | | 50.2% |
| AE Supply | | | — |
| | | 1,000 |
| | | — |
| | | — |
| (3) | | 34.7% |
| FET | | | — |
| | | — |
| | | 1,000 |
| | | — |
| (2) | | 64.4% |
| OE | | | 500 |
| | | — |
| | | — |
| | | 500 |
| (4) | | 61.9% |
| CEI | | | 500 |
| | | — |
| | | — |
| | | 500 |
| (4) | | 62.0% |
| TE | | | 500 |
| | | — |
| | | — |
| | | 500 |
| (4) | | 62.6% |
| JCP&L | | | 425 |
| | | — |
| | | — |
| | | 600 |
| (1)(4) | | 45.6% |
| ME | | | 300 |
| | | — |
| | | — |
| | | 500 |
| (1)(4) | | 54.3% |
| PN | | | 300 |
| | | — |
| | | — |
| | | 300 |
| (1)(4) | | 59.0% |
| WP | | | 200 |
| | | — |
| | | — |
| | | 200 |
| (1)(4) | | 52.7% |
| MP | | | 150 |
| | | — |
| | | — |
| | | 150 |
| (1)(4) | | 54.9% |
| PE | | | 150 |
| | | — |
| | | — |
| | | 150 |
| (1)(4) | | 54.9% |
| ATSI | | | — |
| | | — |
| | | 100 |
| | | 100 |
| (4) | | 48.6% |
| Penn | | | 50 |
| | | — |
| | | — |
| | | 50 |
| (1)(4) | | 41.1% |
| TrAIL | | | — |
| | | — |
| | | 200 |
| | | 400 |
| (1)(4) | | 44.0% |
| | |
(a)(1)
| On June 1, 2012 the joint application, which was filed with the FERC on April 11, 2012, seeking authorization to increase or incur short-term debt, was granted. |
| |
(b)(3)
| | No limitation based upon blanket financing authorization from the FERC under existing open market tariffs. |
| |
(c)(4)
| | ExcludingIncluding amounts which may be borrowed under the regulated companies’companies' money pool. |
As of June 30, 2012, FE and its subsidiaries could issue additional debt of approximately $5.7 billion, or recognize a reduction in equity of approximately $3.1 billion, and remain within the limitations of the financial covenants required by the Facilities.
The entire amount of the New FES/AE Supply Facility, and $700 million of the New FirstEnergy Facility and $225 million of the FET Facility, subject to each borrower’s sub-limit, is available for 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 each of the New Facilities and against the applicable borrower’s borrowing sub-limit.
Each of the New Facilities 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 June 30, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the New Facilities) were as follows:
| | | | |
Borrower | | | | |
FirstEnergy
| | | 56.9 | % |
FES
| | | 54.1 | % |
OE
| | | 56.2 | % |
Penn
| | | 34.4 | % |
CEI
| | | 56.3 | % |
TE
| | | 58.4 | % |
JCP&L
| | | 43.9 | % |
Met-Ed
| | | 53.5 | % |
Penelec
| | | 55.5 | % |
ATSI
| | | 54.9 | % |
MP
| | | 59.3 | % |
PE
| | | 60.1 | % |
WP
| | | 53.9 | % |
AE Supply
| | | 39.4 | % |
As of June 30, 2011, FirstEnergy could issue additional debt of approximately $7.8 billion, or recognize a reduction in equity of approximately $4.2 billion, and remain within the limitations of the financial covenants required by its credit facility.
107
The New Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances as a resultin the event of any change in credit ratings.ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facilities areFacilities is related to the credit ratings of the company borrowing the funds.
In additionfunds, other than the FET Facility, which is based on its subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the New Facilities, FirstEnergy also has access to an additional $500usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.
AGC Revolving Credit Facility
A separate $50 million of revolving credit facilities relatingfacility is available to the Allegheny companies (TrAIL — $450 million and AGC $50 million).
until December 2013. Under the terms of itsthis credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. OutstandingThis provision limits the debt for TrAIL may not exceed 70% and 65%level 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 subsidiariesAGC and also limitlimits the net assets of each subsidiaryAGC that may be transferred to AE. As of June 30, 2012, the debt to total capitalization ratios for AGC (as defined under this credit facility) was 52% and AGC could issue additional debt of approximately $37 million and remain within the limitations of the financial covenants under this credit facility.
FirstEnergy Money Pools
FirstEnergy’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’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 six months of 20112012 was 0.43%0.65% per annum for the regulated companies’ money pool and 0.46%1.24% per annum for the unregulated companies’ money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to become part of the FirstEnergy regulated money pool.
Pollution Control Revenue Bonds
As of June 30, 2011,2012, FirstEnergy’s currently payable long-term debt included approximately $949$713 million (FES — $875($640 million Met-Ed — $29 million and Penelec — $45 million)applicable to FES) 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 FirstEnergyFirstEnergy's variable interest rate PCRBs were issued by the following banks as of June 30, 2011:2012:
| | | | | | | | | |
| | | Aggregate LOC | | | | | Reimbursements of |
| LOC Bank | | Amount(1) | | | LOC Termination Date | | LOC Draws Due |
| | | (In millions) | | | | | |
| UBS | | $ | 272 | | | April 2014 | | April 2014 |
| The Bank of Nova Scotia | | | 178 | | | Beginning June 2012 | | Multiple dates(2) |
| CitiBank N.A. | | | 165 | | | June 2014 | | June 2014 |
| Wachovia Bank | | | 153 | | | March 2014 | | March 2014 |
| The Royal Bank of Scotland | | | 131 | | | June 2012 | | 6 months |
| US Bank | | | 60 | | | April 2014 | | 6 months |
| | | | | | | | |
| Total | | $ | 959 | | | | | |
| | | | | | | | |
|
| | | | | | | | |
| LOC Bank | | Aggregate LOC Amount(1) | | LOC Termination Date | | Reimbursements of LOC Draws Due |
| | | (In millions) | | | | |
| UBS | | $ | 272 |
| | April 2014 | | April 2014 |
| CitiBank N.A. | | 166 |
| | June 2014 | | June 2014 |
| Wachovia Bank | | 152 |
| | March 2014 | | March 2014 |
| The Bank of Nova Scotia | | 49 |
| | April 2014 | | Multiple dates(2) |
| The Bank of Nova Scotia | | 82 |
| | April 2015 | | April 2015 |
| Total | | $ | 721 |
| | | | |
| | |
(1) | | Includes approximately $10$8 million of applicable interest coverage. |
| |
(2) | | ShorterEarlier of 6 months from drawing or the LOC termination date ($49 million) and shorter of one year or LOC termination date ($129 million).date. |
On 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 fixed rate PCRBs (including the $50 million repurchased on March 1) into variable rate modes with LOC support. Also on April 1, 2011, Penelec completed the remarketing of $25 million of non-LOC backed commercial paper rate PCRBs into a variable rate mode with LOC support.
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In connection with the remarketings, approximately $207 million 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 were cancelled on May 31, 2011.
On April 29, Met-Ed redeemed $14 million of PCRBs at par value.
On June 1, 2011, FGCO repurchased $40 million of PCRBs and, subject to market conditions and other considerations, is holding those bonds for future remarketing or refinancing.
On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of FMBs previously delivered to certain of the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.
Long-Term Debt Capacity
As of June 30, 2011,2012, the Ohio Companies and Penn had the aggregate capabilitycapacity to issue approximately $2.5$2.8 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 $100 million and $19 million, respectively.$139 million. As a result of itsthe indenture provisions, CEI and TE cannot incur any additional secured debt. Met-EdME and PenelecPN had the capability to issue secured debt of approximately $363$375 million and $365$385 million, respectively, under provisions of their senior note indentures as of June 30, 2011.2012. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of June 30, 2011,2012, MP, PE and WP had the capabilitycapacity to issue approximately $1.0$1.5 billion of additional FMBs in the aggregate.aggregate under the terms of their FMB indentures. Additionally, the issuance of FMBs by these companies is subject to compliance with the financial covenants of the Facilities and any required regulatory approvals and may be subject to statutory and/or charter limitations.
The Ohio Companies filed an application with the PUCO for a financing order under the Ohio securitization legislation adopted in December 2011, which we expect will be primarily used to assist the Ohio Companies in their planned debt reductions.
Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as of June 30, 2011,2012, FGCO had the capabilitycapacity to issue $2.5$1.8 billion of additional FMBs under the terms of that indenture. Due to the sale of Fremont Energy Center on July 28, 2011, FGCO’s capability to issue additional FMBs was reduced by $510 million. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as of June 30, 2011,2012, NGC had the capabilitycapacity to issue $1.7$2.2 billion of additional FMBs as of June 30, 2011 under the terms of that indenture.
FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of itstheir securities. On February 25, 2011, Moody’s affirmed the ratings and stable outlook of FirstEnergy and its regulated utilities, upgraded AE’s senior unsecured ratings to Baa3 from Ba1 and placed the ratings for FES under review for possible downgrade. On March 1, 2011, Fitch affirmed the ratings and outlook of FirstEnergy and its subsidiaries. The following table displays FirstEnergy’sFE’s and its subsidiaries’ securitiesdebt credit ratings as of July 29, 2011.June 30, 2012:
|
| | | | | | | | | | | | |
| | | Senior Secured | | Senior Unsecured |
| Issuer | | S&P | | Moody’s | | Fitch | | S&P | | Moody’s | | Fitch |
FirstEnergy Corp.FE | | — | | — | | — | | BB+ | | Baa3 | | BBB |
Allegheny | | — | | — | | — | | BB+ | | Baa3 | | — |
| FES | | — | | — | | — | | BBB- | | Baa2Baa3 | | BBB |
| AE Supply | | BBB— | | Baa2— | | BBB— | | BBB- | | Baa3 | | BBB- |
| AGC | | — | | — | | — | | BBB- | | Baa3 | | BBB+BBB |
| ATSI | | — | | — | | — | | BBB- | | Baa1 | | A- |
| CEI | | BBB | | Baa1 | | BBB | | BBB- | | Baa3 | | BBB- |
| JCP&L | | — | | — | | — | | BBB- | | Baa2 | | BBB+ |
Met-EdME | | BBB | | A3 | | A- | | BBB- | | Baa2 | | BBB+ |
| MP | | BBB+ | | Baa1 | | A- | | BBB- | | Baa3 | | BBB+ |
| OE | | BBB | | A3 | | BBB+ | | BBB- | | Baa2 | | BBB |
PenelecPN | | BBB | | A3 | | BBB+ | | BBB- | | Baa2 | | BBB |
| Penn | | BBB+ | | A3 | | BBB+ | | — | | — | | — |
| PE | | BBB+ | | Baa1 | | A- | | BBB- | | Baa3 | | BBB+ |
| TE | | BBB | | Baa1 | | BBB | | — | | — | | — |
| TrAIL | | — | | — | | — | | BBB- | | Baa2A3 | | A- |
| WP | | BBB+ | | A3 | | A- | | BBB- | | Baa2 | | BBB+ |
Changes in Cash Position
As of June 30, 2011,2012, FirstEnergy had $476$94 million of cash and cash equivalents compared to approximately $1 billion$202 million of cash and cash equivalents as of December 31, 2010.2011. As of June 30, 20112012 and December 31, 2010,2011, FirstEnergy had approximately $78$68 million and $13$79 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
109
During the first six months of 2011, FirstEnergy received $1.4 billion from cash dividends and equity repurchases by its subsidiaries and paid $420 million in cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.Sheets.
Cash Flows From Operating Activities
FirstEnergy’s consolidated net cash from operating activities iswas provided primarily by its regulated distribution, regulated transmission and competitive energy services energy delivery services and regulated independent transmission businesses (see Results of Operations above). Net cash provided from operating activities increased by $173was $62 million during the first six months of 20112012 compared towith $1,031 million being provided from operating activities during the same period in 2010,first six months of 2011, as summarized in the following table:
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| Operating Cash Flows | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Net income | | $ | 216 | | | $ | 405 | | | $ | (189 | ) |
| Non-cash charges | | | 1,229 | | | | 789 | | | | 440 | |
| Pension trust contribution | | | (262 | ) | | | — | | | | (262 | ) |
| Working capital and other | | | (152 | ) | | | (336 | ) | | | 184 | |
| | | | | | | | | | |
| | | $ | 1,031 | | | $ | 858 | | | $ | 173 | |
| | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| Operating Cash Flows | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Net income | | $ | 494 |
| | $ | 240 |
| | $ | 254 |
|
| Non-cash charges | | 817 |
| | 1,201 |
| | (384 | ) |
| Pension trust contributions | | (600 | ) | | (262 | ) | | (338 | ) |
| Working capital and other | | (649 | ) | | (148 | ) | | (501 | ) |
| | | $ | 62 |
| | $ | 1,031 |
| | $ | (969 | ) |
The increase$384 million decrease in non-cash charges and other adjustments is primarily due to increased deferred taxesthe following:
$129 million from accrued compensation and investment tax credits driven by bonus depreciation andretirement benefits as a result of higher performance-related incentive compensation payments during the first six months of 2012 compared to the same period of 2011 pension contribution ($393 million) and increased depreciation.
$85 million from the acquired Allegheny Companies ($119 million), partially offset by lower net amortization of regulatory assets from reduced net PJM transmission costas a result of the suspension of the rider recovering deferred distribution costs in September 2011 and transitionthe completion of JCP&L's NUG deferred cost recovery, ($151 million).partially offset by the recovery in Ohio of residential generation credits for electric heating discounts, which began in September 2011.
$175 million from decreased deferred income taxes as a result of a change in bonus depreciation.
The increase$501 million decrease in cash flows from working capital and other is primarily due to decreased receivablesthe following:
$304 million from higher customerlower collections ($355 million) and decreasedfrom customers during the first six months of 2012 as a result of the effects of milder weather described in Results of Operations above.
$133 million from increased materials and supplies frombalances as a result of increased coal inventories and the absence in 2012 of the $67 million non-cash inventory valuation adjustment recorded in connection with the first quartermerger.
$94 million from lower accounts payable balances as a result of 2011 ($41 million), partially offset by increased prepayments and other current assets driven by higher prepaid taxes ($187 million).
Cash Flows From Financing Activities
Inthe timing of payments to vendors during the first six months of 2011,2012 as compared to the same period of 2011.
Cash Flows From Financing Activities
In the first six months of 2012, cash provided from financing activities was $831 million compared to $1,039 million of net cash used for financing activities was $1,039 million compared to $484 million induring the comparable periodfirst six months of 2010.2011. The following table summarizestables summarize new debt financing (net of any discounts) and redemptions:
| | | | | | | | | |
| | | Six Months | |
| | | Ended June 30 | |
| Debt Issuances and Redemptions | | 2011 | | | 2010 | |
| | | (In millions) | |
New Issues | | | | | | | | |
| Pollution control notes | | $ | 272 | | | $ | — | |
| Long-term revolving credit | | | 70 | | | | — | |
| Unsecured Notes | | | 161 | | | | — | |
| | | | | | | |
| | | $ | 503 | | | $ | — | |
| | | | | | | |
| | | | | | | | | |
Redemptions | | | | | | | | |
| Pollution control notes | | $ | 312 | | | $ | 251 | |
| Long-term revolving credit | | | 475 | | | | — | |
| Senior secured notes | | | 166 | | | | 55 | |
| First mortgage bonds | | | 14 | | | | — | |
| Unsecured notes | | | 35 | | | | 100 | |
| | | | | | | |
| | | $ | 1,002 | | | $ | 406 | |
| | | | | | | |
| | | | | | | | | |
| Short-term borrowings, net | | $ | (44 | ) | | $ | 281 | |
| | | | | | | |
In 2011, FES paid off at maturity a $100 million term loan that was secured by FMBs. In April 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity. |
| | | | | | | | |
| | | Six Months
Ended June 30 |
| Securities Issued or Redeemed / Retired | | 2012 | | 2011 |
| | | (In millions) |
| New Issues | | | | |
| PCRBs | | $ | 82 |
| | $ | 272 |
|
| Long-term revolving credit | | — |
| | 70 |
|
| FMBs | | 100 |
| | — |
|
| Unsecured Notes | | — |
| | 161 |
|
| | | $ | 182 |
| | $ | 503 |
|
Redemptions / Retirements | | | | |
| PCRBs | | $ | 82 |
| | $ | 312 |
|
| Long-term revolving credit | | — |
| | 475 |
|
| Senior secured notes | | 81 |
| | 166 |
|
| FMBs | | — |
| | 14 |
|
| Unsecured notes | | 583 |
| | 35 |
|
| | | $ | 746 |
| | $ | 1,002 |
|
| | | | | |
| Short-term borrowings, net | | $ | 1,890 |
| | $ | (44 | ) |
110
In 2011 FESOn August 1, 2012, FGCO mandatorily repurchased and retired $20approximately $106.5 million of its 6.80% unsecured senior notes and $15 million of its 6.05% unsecured senior notes. In April 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 through redemptions, open market4.75% PCRBs, which it is holding for future remarketing or privately negotiated purchases. Any such transactions will berefinancing subject to prevailing market conditions, liquidity requirements, timing of asset sales and other factors.conditions.
Cash Flows From Investing Activities
Cash used for investing activities in the first six months of 2011 resulted from2012 principally represented cash used for property additions, partially offset by the cash acquired in the Allegheny merger.additions. The following table summarizes investing activities for the first six months of 20112012 and the comparable period of 2010 by business segment:2011:
| | | | | | | | | | | | | | | | | |
| Summary of Cash Flows | | Property | | | | | | | | | | |
| Provided from (Used for) Investing Activities | | Additions | | | Investments | | | Other | | | Total | |
| | | (In millions) | |
Sources (Uses) | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2011 | | | | | | | | | | | | | | | | |
| Regulated distribution | | $ | (479 | ) | | $ | (2 | ) | | $ | (25 | ) | | $ | (506 | ) |
| Competitive energy services | | | (411 | ) | | | (32 | ) | | | (335 | ) | | | (778 | ) |
| Regulated independent transmission | | | (72 | ) | | | (1 | ) | | | (1 | ) | | | (74 | ) |
| Cash received in Allegheny merger | | | — | | | | 590 | | | | — | | | | 590 | |
| Other and reconciling items | | | (56 | ) | | | (21 | ) | | | 310 | | | | 233 | |
| | | | | | | | | | | | | |
| Total | | $ | (1,018 | ) | | $ | 534 | | | $ | (51 | ) | | $ | (535 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
Six Months Ended June 30, 2010 | | | | | | | | | | | | | | | | |
| Regulated distribution | | $ | (309 | ) | | $ | 87 | | | $ | (18 | ) | | $ | (240 | ) |
| Competitive energy services | | | (619 | ) | | | (11 | ) | | | (1 | ) | | | (631 | ) |
| Regulated independent transmission | | | (29 | ) | | | — | | | | (2 | ) | | | (31 | ) |
| Other and reconciling items | | | (40 | ) | | | (25 | ) | | | — | | | | (65 | ) |
| | | | | | | | | | | | | |
| Total | | $ | (997 | ) | | $ | 51 | | | $ | (21 | ) | | $ | (967 | ) |
| | | | | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| Cash Used for (Provided from) Investing Activities | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Property Additions: | | | | | |
|
|
| Regulated distribution | | $ | 443 |
| | $ | 381 |
| | $ | 62 |
|
| Regulated transmission | | 122 |
| | 170 |
| | (48 | ) |
| Competitive energy services | | 393 |
| | 411 |
| | (18 | ) |
| Other and reconciling adjustments | | 43 |
| | 56 |
| | (13 | ) |
| Cash received in Allegheny merger | | — |
| | (590 | ) | | 590 |
|
| Investments | | (49 | ) | | 54 |
| | (103 | ) |
| Other | | 49 |
| | 53 |
| | (4 | ) |
| | | $ | 1,001 |
| | $ | 535 |
| | $ | 466 |
|
Net cash used infor investing activities during the first six months of 2011 decreased2012 increased by $432$466 million compared to the same period of 2010.2011. The decreaseincrease was principally due to the absence in 2012 of cash acquired in the Allegheny merger ($($590 million)million), partially offset by a decrease in net proceeds from asset sales and higher property additions ($13717 million), a decrease in net purchases of investment securities ($66 million) and
additional restricted cash investments ($37 million).
During the second halfremainder of 2011,2012, capital requirements for property additions and capital leases are expectedestimated to be approximately $1.2$1.4 billion, including approximately $122$201 million for nuclear fuel.
GUARANTEES AND OTHER ASSURANCES
As part
FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of normal business activities, FirstEnergy enters into various agreements on behalfbusiness. These contracts include performance guarantees, stand-by letters of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contractcredit, debt guarantees, surety bonds and LOCs. Someindemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the guaranteed contracts contain collateral provisions that are contingent upon eithertransaction to the third party. The maximum potential amount of future payments FirstEnergy or its subsidiaries’ credit ratings.
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Ascould have been required to make under these guarantees as of June 30, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.82012, was approximately $4.1 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) | | $ | 223 | |
| OVEC obligations | | | 300 | |
Other(2) | | | 301 | |
| | | | |
| | | | 824 | |
| | | | |
| | | | | |
| Subsidiaries’ Guarantees | | | | |
| Energy and Energy-Related Contracts | | | 155 | |
| FES’ guarantee of NGC’s nuclear property insurance | | | 70 | |
| FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,324 | |
| Other | | | 19 | |
| | | | |
| | | | 2,568 | |
| | | | |
| | | | | |
| Surety Bonds | | | 136 | |
LOC(3) | | | 269 | |
| | | | |
| | | | 405 | |
| | | | |
| Total Guarantees and Other Assurances | | $ | 3,797 | |
| | | | |
|
| | | | |
| Guarantees and Other Assurances | | Maximum Exposure |
| | | (In millions) |
| FirstEnergy Guarantees on Behalf of its Subsidiaries | | |
Energy and Energy-Related Contracts(1) | | $ | 287 |
|
LOC (long-term debt) - interest coverage(2) | | 5 |
|
| OVEC obligations | | 300 |
|
Other(3) | | 296 |
|
| | | 888 |
|
| Subsidiaries’ Guarantees | | |
| Energy and Energy-Related Contracts | | 137 |
|
LOC (long-term debt) - interest coverage(2) | | 3 |
|
| FES’ guarantee of NGC’s nuclear property insurance | | 85 |
|
| FES’ guarantee of FGCO’s sale and leaseback obligations | | 2,199 |
|
| Other | | 12 |
|
| | | 2,436 |
|
| Signal Peak & Global Rail facility | | 350 |
|
| Surety Bonds | | 221 |
|
LOCs(4) | | 173 |
|
| | | 744 |
|
| Total Guarantees and Other Assurances | | $ | 4,068 |
|
| | |
(1) | | Issued for open-ended terms, with a 10-day termination right by FirstEnergy. |
| |
(2) | Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $713 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets. |
| |
(3) | Includes guarantees of $95$95 million for nuclear decommissioning funding assurances, $161$161 million supporting OE’s sale and leaseback arrangement,arrangements, and $35$32 million for railcar leases. |
| |
|
(3)(4)
| | Includes $105$32 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $122$108 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $39$34 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
Of this amount, substantially all relates to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy 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 an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $625 million, as shown below:
| | | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | | AE Supply | | | Utilities | | | Total | |
| | | (In millions) | |
Credit rating downgrade to below investment grade (1) | | $ | 440 | | | $ | 4 | | | $ | 78 | | | $ | 522 | |
Material adverse event (2) | | | 33 | | | | 57 | | | | 13 | | | | 103 | |
| | | | | | | | | | | | | |
| Total | | $ | 473 | | | $ | 61 | | | $ | 91 | | | $ | 625 | |
| | | | | | | | | | | | | |
| | |
(1) | | Includes $206 million and $59 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively. |
|
(2) | | Includes $32 million that is also considered an acceleration of payment or funding obligation for FES. |
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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 $666 million, as shown below:
| | | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | | AE Supply | | | Utilities | | | Total | |
| | | (In millions) | |
Credit rating downgrade to below investment grade (1) | | $ | 477 | | | $ | 5 | | | $ | 78 | | | $ | 560 | |
Material adverse event (2) | | | 36 | | | | 57 | | | | 13 | | | | 106 | |
| | | | | | | | | | | | | |
| Total | | $ | 513 | | | $ | 62 | | | $ | 91 | | | $ | 666 | |
| | | | | | | | | | | | | |
| | |
(1) | | Includes $206 million and $59 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively. |
|
(2) | | Includes $32 million that is also considered an acceleration of payment or funding obligation for FES. |
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $136 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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $138 million and $2 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 $17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.
FES’wholly-owned consolidated entities. FES' debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO, and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.
Collateral and Contingent-Related Features
As part of the normal course of business, FirstEnergy and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuels, and emissions allowances. Certain bilateral agreements and derivative instruments contain provisions that require FirstEnergy or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FirstEnergy's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.
Bilateral agreements and derivative instruments entered into by FirstEnergy and its subsidiaries have margining provisions that require posting of collateral.Based on FES' and AE Supply's power portfolio exposure as ofJune 30, 2012, FES has posted collateral
of$36 million. The Regulated Distribution segment has posted collateral of$9 million.
These credit-risk-related contingent features stipulate that if the subsidiaries were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.
Subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FirstEnergy or its subsidiaries.The following chart discloses the additional credit contingent contractual obligations as ofJune 30, 2012:
|
| | | | | | | | | | | | | | | | |
| Collateral Provisions | | FES | | AE Supply | | Utilities | | Total |
| | | (In millions) |
| Split Rating (One rating agency's rating below investment grade) | | $ | 373 |
| | $ | 6 |
| | $ | 40 |
| | $ | 419 |
|
| BB+/Ba1 Credit Ratings | | $ | 429 |
| | $ | 6 |
| | $ | 59 |
| | $ | 494 |
|
| Full impact of credit contingent contractual obligations | | $ | 658 |
| | $ | 73 |
| | $ | 73 |
| | $ | 804 |
|
Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Segment.As ofJune 30, 2012neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$46 millionand$13 million, respectively.
Other Commitments and Contingencies
Signal Peak and Global Rail are borrowers under a $350$350 millionsyndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that shareoriginally shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers’borrowers' obligations under the facility. Following the sale of a portion of FEV's ownership interest in Signal Peak and Global Rail in the fourth quarter of 2011, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding, continued to guarantee the borrowers' obligations under the current facility. In addition, FEV, Global Mining Group, LLC and Global Holding, the other entities that directly own thedirect and indirect equity interestinterests in the borrowers, have pledged those interests to the lenders under the term loancurrent facility as collateral forcollateral.Global Holding is involved in negotiations to refinance the facility.current facility with a bank facility under which it would be the borrower. In connection with such proposed refinancing, FirstEnergy expects to provide the new lenders with a guarantee of Global Holding's obligations, and FirstEnergy and WMB Marketing Ventures, LLC expect to pledge not less than two-thirds of the equity interests in Global Holding and its subsidiaries.
OFF-BALANCE SHEET ARRANGEMENTS
FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $1.6$1.5 billion as of June 30, 2011.2012, of which $121 million is applicable to the 1987 Bruce Mansfield Plant leases, which may be terminated pursuant to an early buyout option. In March 2012, FGCO, as assignee, provided notice of its irrevocable election of the early buyout option of the 1987 Bruce Mansfield Plant leases. The purchase price to be paid by FGCO will be equal to the higher of the special termination value under the applicable facility leases (in the aggregate approximately $435 million, covering both debt and equity under the leases) and the fair market value. FGCO has reached preliminary agreement with some of the parties on the purchase price and certain other parties have invoked an appraisal process to determine the fair market value. On August 2, 2012, FGCO completed the acquisition of the equity interest in certain of the 1987 Bruce Mansfield Plant leases with two owner participants totaling approximately $69.4 million. From time to time we also enter into discussions with certain parties to the arrangements regarding acquisition of owner participant and other interests. We cannot provide assurance that any such acquisitions will occur on satisfactory terms or at all.
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. FirstEnergy’s Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.
Commodity Price Risk
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 established aFirstEnergy's Risk Policy Committee, comprised of members of senior management, which provides general management oversight for risk management activities throughout FirstEnergy. TheManagement 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 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.
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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 56, Fair Value Measurements of the Combined Notes to the consolidated financial statements)Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of June 30, 20112012 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) | | | (287 | ) | | | (169 | ) | | | (48 | ) | | | (38 | ) | | | — | | | | — | | | | (542 | ) |
| Prices based on models | | | 9 | | | | (3 | ) | | | — | | | | — | | | | — | | | | 44 | | | | 50 | |
| | | | | | | | | | | | | | | | | | | | | | |
Total(3) | | $ | (278 | ) | | $ | (172 | ) | | $ | (48 | ) | | $ | (38 | ) | | $ | — | | | $ | 44 | | | $ | (492 | ) |
| | | | | | | | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Source of Information- Fair Value by Contract Year | | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | Thereafter | | Total |
| | | (In millions) |
Prices actively quoted(1) | | $ | 3 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | 3 |
|
Other external sources(2) | | (100 | ) | | (45 | ) | | (26 | ) | | (27 | ) | | — |
| | — |
| | (198 | ) |
| Prices based on models | | 4 |
| | — |
| | — |
| | — |
| | (22 | ) | | (143 | ) | | (161 | ) |
Total(3) | | $ | (93 | ) | | $ | (45 | ) | | $ | (26 | ) | | $ | (27 | ) | | $ | (22 | ) | | $ | (143 | ) | | $ | (356 | ) |
| | |
(1) | | Represents exchange traded New York Mercantile Exchange futures and options. |
| |
(2) | | Primarily represents contracts based on broker and IntercontinentalExchange, Inc. quotes. |
| |
|
(3) | | Includes $445$(438) 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. Based on derivative contracts held as of June 30, 2011,2012, an adverse 10% change in commodity prices would decrease net income by approximately $31$2 million ($20 million net of tax) during the next 12 months.
Interest Rate Risk
In the second quarter of 2012, FirstEnergy executed a total of $1.6 billion forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%.
Equity Price Risk
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.
The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of June 30, 2011,2012, the FirstEnergy pension plan was investedassets were in approximately 31% of21% in equity securities, 46% of52% in fixed income securities, 9% of17% in absolute return strategies, 6% of5% in real estate, 4% of2% in private equity and 4% of3% in cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011,2012, FirstEnergy made contributionsa voluntary pre-tax contribution to its qualified pension plans of $105$600 million. See Note 3, Pensions and $262 million, respectively. FirstEnergy intendsOther Postemployment Benefits, to makethe Consolidated Financial Statements for additional contributions of $116 million and $2 million to its qualifieddetails on FirstEnergy's pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.OPEB.
NDT funds have been established to satisfy NGC’s, OE's, JCP&L's and the Utilities’other FE subsidiaries' nuclear decommissioning obligations. As of June 30, 2011,2012, approximately 87%82% of the funds were invested in fixed income securities, 10%13% of the funds were invested in equity securities and 3%5% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,779$1,780 million, $197$280 million and $69$100 million for fixed income securities, equity securities and short-term investments, respectively, as of June 30, 2011,2012, excluding $6$7 million of net receivables, payables deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $20$28 million reduction in fair value as of June 30, 2011. The2012. JCP&L's decommissioning trusts of JCP&L and the Pennsylvania Companies aretrust is subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC OE and TEOE recognize in earnings the unrealized losses on available-for-sale securities held in their NDT as other-than-temporary impairments.OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the first sixthree months of 2011,ended June 30, 2012, approximately $1 million, $4 million and $1 million was contributed to NDT of JCP&L, OE and TE, respectively. On March 28, 2011,OE's NDT. FENOC has submitted its biennial report on nuclear decommissioning fundinga $95 million parental guarantee to the NRC. This submittal identifiedNRC relating to a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of $92 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.Perry.
CREDIT RISK
Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an obligor’s failure to meetongoing basis. An independent risk management group oversees credit risk.
Wholesale Credit Risk
FirstEnergy measures wholesale credit risk as the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activitiesreplacement cost for derivatives 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 includingpower, natural gas, electricity, coal and emission allowances. These transactions are often with majorallowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of set-off. FirstEnergy
monitors and manages the credit risk of wholesale marketing, risk management and energy companies within the industry.
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FirstEnergy maintainstransacting operations through credit policies with respect to its counterparties to manage overalland procedures, which include an established credit risk. This includes performing independent risk evaluations, activelyapproval process, daily monitoring portfolio trends and usingof counterparty credit limits, the use of credit mitigation measures such as margin, collateral and contract provisions to mitigate exposure. As partthe use of its credit program,master netting agreements. FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced bycurrently having a current weighted average risk rating for energy contract counterparties of BBB (S&P).
Retail Credit Risk
FirstEnergy's principal retail credit risk exposure relates to its competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.
Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.
Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.
OUTLOOK
STATE REGULATION
Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.
MARYLAND
PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions overseen by the MDPSC and a third party monitor. The settlements with respect to residential SOS for PE customers expire on December 31, 2012, but by statute service will continue in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential service have expired but, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by10%and reduce electricity demand by15%, in each case by 2015. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately$101 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsix-year period. Maryland law only allows for the utility to recover lost distribution revenue attributable to the energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE.Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan that includes additional and improved programs for the period 2012-2014.The plan is expected to cost approximately$66 millionover the three-year period.The MDPSC held hearings on PE and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving PE's plan with various modifications and follow-up assignments.
Pursuant to a bill passed by the Maryland legislature, the MDPSC proposed rules, based on the product of a working group of utilities, regulators, and other interested stakeholders, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The bill requires that the MDPSC consider cost-effectiveness, and provides that the MDPSC 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 required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day, per violation.Further comments were filed regarding the proposed rules on March 26, 2012, and at a hearing on April 17, 2012, the MDPSC approved re-publication of the rules as final.
NEW JERSEY
JCP&L currently provides BGS for retail customers that do not choose a third party electric generation supplier and for customers of third party electric generation suppliers that fail to provide the contracted service. The supply for BGS, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of
which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The most recent BGS auction results, for supply commencing June 1, 2012, were approved by the NJBPU on February 9, 2012.
On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable.In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.
Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held to solicit comments regarding the state of preparedness and responsiveness of the EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the report of the consultant is due to be submitted to the NJBPU in August 2012.The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.
OHIO
The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:
Generation supplied through a CBP commencing June 1, 2011;
A load cap of no less than80%, so that no single supplier is awarded more than80%of the tranches, which also applies to tranches assigned post-auction;
A6%generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies);
No increase in base distribution rates through May 31, 2014; and
A new distribution rider, Rider DCR, to recover a return of, and on, capital investments in the delivery system.
The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI's integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent 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 and alternative energy requirements.
On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012.
As approved, the ESP 3 plan will maintain the substantial benefits from the current ESP including:
Freezing current base distribution rates through May 31, 2016;
Continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;
Providing Percentage of JuneIncome Payment Plan customers with a 6 percent generation rate discount;
Continuing to provide power to shopping and to non-shopping customers as part of the market-based price set through an auction process; and
Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.
As approved, the ESP 3 plan will provide additional new benefits, including:
Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and
Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.
The filing is supported by19parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).Sevenadditional parties agreed not to oppose the filing.
Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately1,211GWHs in 2012 (an increase of416,000MWHs over 2011 levels),1,726GWHs in 2013,2,306GWHs in 2014 and2,903GWHs for each year thereafter through 2025.Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75% reduction each year thereafter through 2018.
In December 2009, the Ohio Companies filed theirthree-year portfolio plan, as required by SB221, seeking approval for the programs they intended to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. In March 2011, the PUCO issued an Opinion and Order generally approving the Ohio Companies' 2010-2012 portfolio plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies have implemented those programs included in the plan. However, due to the timing of the approval of the plan, the Ohio Companies requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks for 2010. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the issue was moot for CEI and TE because they achieved their targets in that year. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO.
The Ohio Companies had filed applications for rehearing regarding portions of the PUCO's decision related to the Ohio Companies'three-year portfolio plan, which was later denied. On December 30, 2011, the largest credit concentrationOhio Companies filed a notice of appeal with the Supreme Court of Ohio, which was dismissed on June 20, 2012. In accordance with J.P. Morgan Chase & Co., whichPUCO Rules and a PUCO directive, the Ohio Companies filed their next three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.
Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. The PUCO selected auditors to perform a financial and management audit, and final audit reports are currently scheduled to be filed with the PUCO on August 15, 2012. In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies have achieved their in-state solar compliance requirements for 2012.
PENNSYLVANIA
The Pennsylvania Companies currently operate under DSPs that expire May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative electric generation supplier or for customers of alternative electric generation suppliers that fail to provide the contracted service. The default service supply is currently rated investment grade, representing 11%provided by wholesale suppliers through a mix of FirstEnergy’s totallong-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On November 17, 2011, the Pennsylvania Companies filed a Joint Petition for Approval of their DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015.The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. Exceptions to the Recommended Decision are currently pending.A final order must be entered by the PPUC by August 17, 2012.
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved credit risk comprisedby the PPUC, ME and PN began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission losses are refunded. In April 2010, ME and PN filed a Petition for Review with the Commonwealth Court of 2.4%Pennsylvania appealing the PPUC's March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC's Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately$254 millionin marginal transmission losses and associated carrying charges for FES, 1.6%the period prior to January 1, 2011, are not recoverable under ME and PN TSC riders. ME and PN filed a Petition for JCP&L, 2.0%Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for Met-Ed, 3.4%the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss ME and PN Amended Complaint on September 15, 2011 to which ME and PN responded and which remains pending.On February 28, 2012, the Supreme Court of Pennsylvania denied the Petition for Allowance of Appeal.On June 27, 2012, ME and PN filed a Petition for Writ of Certiorari with the Supreme Court of the United States. The PPUC's brief in opposition is due on August 31, 2012, and the ME/PE reply is due on September 10, 2012. If the Supreme Court declines to take the case then ME and PE will pursue their claims in the proceedings that are pending in the U.S. District Court (E.D. PA).
In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN's annual updates to their TSC rider for the annual periods
between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal transmission losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC's approval in May 2010 authorized an increase to the TSC for ME's customers to provide for full recovery by December 31, 2010. Although the ultimate outcome of this matter cannot be determined at this time, ME and PN believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 millionin marginal transmission losses for the period prior to January 1, 2011.
Pennsylvania adopted Act 129 in 2008 to 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 (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.
On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of ME, PN and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements. On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding, and the ALJ's Recommended Decision was issued on April 19, 2012, recommending that the Joint Settlement be adopted as filed.The PPUC entered an order on May 10, 2012 approving the Joint Settlement.
In addition, Act 129 required utilities to file a SMIP with the PPUC. 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 its previously approved smart meter deployment plan and certain smart meter dependent aspects of the EE&C Plan. WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. WP also proposed to take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. 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. A joint settlement with all parties based on these terms, with one party retaining the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan, was approved by the PPUC on June 30, 2011. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file by the end of 2012, or in a future base distribution rate case.The deadline for the Pennsylvania Companies to file their smart meter deployment plan is December 31, 2012.
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. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the PPUC entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming DSPs, including: the duration of the programs and the length of associated energy contracts; a customer referral program; a retail opt-in auction; time-of-use rate options provided through contracts with electric generation suppliers; and periodic rate adjustments.Following the issuance of a Tentative Order and comments filed by various parties, the PPUC entered a final order on March 2, 2012 outlining an intermediate work plan. Several suggested models for long-range default service have been presented and were the topic of a March 2012 en banc hearing. It is expected that a tentative order will be issued for comment with a final long-range proposal.
The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by ME, PN, Penn, WP and FES on March 27, 2012. If implemented these rules could require a combined 2.0%significant change in the ways FES, ME, PN, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and
financial condition.Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on April 26, 2012, on the proposed rulemaking, which called for the Ohio Companies.PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them.
OUTLOOK
Reliability InitiativesWEST VIRGINIA
In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in a proceeding for an annual increase in retail rates that provided for:
$40 millionannualized base rate increases effective June 29, 2010;
Deferral of February 2010 storm restoration expenses over a maximumfive-year period;
Additional$20 millionannualized base rate increase effective in January 2011;
Decrease of$20 millionin ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and
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 January 2011, MP and PE filed an application with the WVPSC seeking to certifythreefacilities as Qualified Energy Resource Facilities for purposes of compliance with their approved plan pursuant to AREPA. The application was approved and thethreefacilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP is entitled to all alternative and 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 andthreeNUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, have participated in the case in opposition to the petition. The WVPSC issued an order granting ownership of all RECs produced by the facilities to MP.The West Virginia Supreme Court issued an Order on June 11, 2012, upholding the WVPSC's decision.
The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC alleging the WVPSC order violated PURPA and requested FERC initiate an enforcement action. On April 24, 2012, the FERC ruled that the FERC-jurisdictional contracts are intended to pay only for electric energy and capacity (and not for RECs), and that state law controlled on the issues of determining which entity owns RECs and how they are transferred between entities. The FERC declined to act on the complaints and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court.FERC also noted there may be language in the WVPSC decision that is inconsistent with PURPA. MP filed for rehearing of the FERC's order taking the position that the WVPSC order is consistent with PURPA. New Martinsville filed a complaint in the U.S. District Court on June 4, 2012, alleging that the WVPSC order violates PURPA.
On March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.
RELIABILITY MATTERS
Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO charged with establishingdesignated by FERC to establish and enforcingenforce these reliability standards, although itNERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including ReliabilityFirstCorporation.RFC. All of FirstEnergy’sFirstEnergy's facilities are located within the ReliabilityFirstRFC region. FirstEnergy actively participates in the NERC and ReliabilityFirstRFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by the ReliabilityFirstCorporation.RFC.
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.RFC. Moreover, it is clear that the NERC, ReliabilityFirstRFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Still, anyAny future inability on FirstEnergy’sFirstEnergy's part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.
On December 9, 2008, a transformer at JCP&L’s&L's Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up toelevenhours. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s&L's contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests.On March 22, 2012, NERC concluded the investigation of the matter and forwarded it to NCEA for further review. NCEA is currently evaluating the findings of the investigation. JCP&L is not ableexpects the matter to predict what actions, if any, thatbe resolved for an immaterial amount.
In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the NERC may take with respectaudited systems and processes to this matter.
On August 23, 2010, FirstEnergy self-reported to ReliabilityFirsta vegetation encroachment event on a Met-Ed 230 kV line. This event did not resultbe 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, although a final determination has not yet been made by FERC.
Allegheny has been subject to routine audits with respect to itsfull compliance with applicableall audited reliability standardsstandards. RFC will perform additional audits in 2012.
FERC MATTERS
PJM Transmission Rate
PJM and has settled certain related issues. In addition, ReliabilityFirstis currently conducting certain investigations with regard to certain matters of compliance by Allegheny.
Maryland
By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. 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.
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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 order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedingsstakeholders have been set bydebating the MDPSC in this matter.
In September 2007, the MDPSC issued an order that required the Maryland utilitiesproper method to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.
The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the 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. 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 and those programs are to be filed by September 1, 2011.
In March 2009, the MDPSC 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. 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 summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.
On March 24, 2011, the MDPSC 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. The Maryland legislature passed a bill on April 11, 2011, which 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 legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC 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 proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.
New Jersey
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). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).
Ohio
The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies 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 (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI’s 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 and alternative energy requirements.
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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 to approximately 166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in 2012 and 530,000 MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.
In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The 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. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and 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. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were 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 them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.
Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On 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. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. 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 credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect 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 authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.
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Pennsylvania
The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 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 ofallocate costs for marginalnew transmission losses.facilities. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accountsmatter is contentious because costs for marginalfacilities built in one transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amountszone often are allocated to customers in January 2011,other transmission zones. During recent years, the debate has focused on the question of the methodology for determining the transmission zones and customers who benefit from a given facility and, if so, whether the refunds will continue overmethodology can determine the pro rata share of each zone's benefit. While FirstEnergy and other parties advocated for a 29 month period untiltraditional "beneficiary pays" approach, others advocate for “socializing” the full amounts previously recovered for marginal transmission loses are refunded. costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. This debate is framed by regulatory and court decisions.In April 2010, Met-Ed and Penelec filed a Petition for Review with2007, the CommonwealthU.S. Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying chargesAppeals for the periodSeventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of21, 2010, FERC set this matter cannot be determined at this time, Met-Edfor a “paper hearing” and Penelec believerequested parties to submit written comments. FERC identifiednineseparate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.
In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcomeallocation of the proceeding related tocost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.
In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 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 in 2008 to 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. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).
The PPUC entered an Order in February 2010 giving final approval to all aspectsmajority of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.
WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that 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 does not meet the Total 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 deployment, which the PPUC approved in January 2011.
Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the 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.
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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, 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 OCA 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 considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. 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 OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.
By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, variouscosts. Subsequently, numerous parties filed responsive comments objecting to the above accounting method utilized by Met-Edor studies on May 28, 2010 and Penelec. 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. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted jointreply comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011,28, 2010. FirstEnergy and a number of other utilities, industrial customers and state utility commissions supported the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.
Virginia
In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portionsuse of the PATH Project. beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis.On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.
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West Virginia
In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 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;
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; |
|
| • | | 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 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. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.
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 and 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 and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.
FERC Matters
Rates for Transmission Service Between MISO and PJM
In November 2004,March 30, 2012, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initialon remand reaffirming its prior decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.
PJM Transmission Rate
In April 2007, FERC issued an order (Opinion 494) finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, FERC directed that costs for new transmission facilities that are rated at500kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate based on the amount of load served in a transmission zone. Costszone and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order.
Order No. 1000 issued by FERC on July 21, 2011, requires the submission of a compliance filing in October 2012 by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission facilities that are rated at less than 500 kV, however, areprojects directed by the PJM Board of Managers satisfies the principles set forth in the order. The PJM transmission owners have announced their intention to submit a compliance filing based on a hybrid methodology of 50% beneficiary pays and 50% postage stamp (or socialization) to be allocatedeffective for projects approved by the PJM Board on a load flow methodology (DFAX), whichand after the effective date of the compliance filing. FirstEnergy is generally referredworking with other PJM transmission owners to as a “beneficiary pays” approach to allocatingdevelop the cost of high voltage transmission facilities.
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FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and,required filing based on this finding, remanded the rate design issue back to FERC.proposed methodology.
In an order dated January 21, 2010, FERC set the matter for a “paper hearing”— meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.
RTO Realignment
On June 1, 2011, ATSI and the ATSI zone entered intotransferred from MISO to PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.
On February 1, 2011, ATSI in conjunction While most of the matters involved with PJM filed its proposal with FERCthe move have been resolved, the question of ATSI's responsibility for moving its transmission rate into PJM’s tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEPcertain costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose“Michigan Thumb” transmission project continues to be disputed; the details of effecting movement ofwhich dispute are discussed below in the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.
On May 31, 2011,"MISO Multi-Value Project Rule Proposal." In addition, FERC issued orders that address the proposed ATSI transmission rate, anddenied certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges forof ATSI's transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission ratesrate until such time as ATSI files and FERC approvessubmits a cost/benefit analysis that demonstrates net benefits to customers from the cost-benefit study. On June 30, 2011,move. ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requestedhas asked for rehearing of FERC’s decision to require a cost-benefit study analysisFERC's orders that address the Michigan Thumb transmission project, and the exit fee issue.
ATSI's filings and requests for rehearing on these matters, as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing,well as the pleadings submitted by parties that oppose ATSI's position are currently pending before FERC.
From late April 2011 through June 2011, FERC issued other orders Finally, a negotiated agreement that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement betweenrequires ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreementa one-time charge of ATSI’s responsibility $1.8 millionfor certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. ATSI's exit, is pending before FERC.
The final outcome of those proceedings that address the remaining open issues related to ATSI’sATSI's move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.
MISO Multi-Value Project Rule Proposal
In July 2010, MISO and certain MISO transmission owners (not including ATSI or FirstEnergy) jointly filed with FERC theira proposed cost allocation methodology for certain new transmission projects. The new transmission projects—projects - described as MVPs —- are a class
of transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.”MISO's MTEP process. Under MISO’sMISO's proposal, the costs of “Michigan Thumb” MVP projects that were approved by MISO’sMISO's Board prior to the June 1, 2011 effective date of FirstEnergy’sFirstEnergy's integration into PJM would continue to be allocated to FirstEnergy.and charged to ATSI. MISO estimated that approximately $15$15 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone associated withupon completion of project construction.
FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project upon its completion.onto ATSI or onto ATSI's customers that assert legal, factual and policy arguments.To date, FERC has responded in a series of orders that require ATSI to absorb the charges for the Michigan Thumb Project.
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In September 2010,On October 31, 2011, FirstEnergy filed a protest toPetition of Review of certain of the MVP proposal arguing that MISO’s proposal to allocate costs of MVPs projects across the entire MISO footprint does not alignFERC's orders with the established rule that cost allocation isU.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit with briefs due from the parties through 2012 and oral argument to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that,scheduled in light2013.
In February 2012, FERC issued its most recent order (February 2012 Order) regarding the Michigan Thumb Project, in which FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of progress that had been madeMVP charges to date inATSI. MISO's Schedule 39 tariff is the ATSI integration into PJM, it would be unjust and unreasonablevehicle through which the MISO plans to allocate any MVPcharge the Michigan Thumb project costs to ATSI.FERC also set for hearing the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.
In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as toquestion of whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligateit is just and reasonable for ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question ofMichigan Thumb project costs and, if so, the amount of costs that are to be allocated to ATSI or to load inand methodology for calculating ATSI's Michigan Thumb project cost responsibility.On March 28, 2012, FirstEnergy filed for clarification and rehearing of the ATSI zone were beyondFebruary 2012 Order, and such request is pending before the FERC.On July 10, 2012, a prehearing conference was convened before a FERC ALJ who will determine the scope of FERC’s orderthe hearing and would be addressed in future proceedings.thereafter set the hearing schedule.
On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.
As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost-benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.
FirstEnergy cannot predict the outcome of these proceedings at this time.or estimate the possible loss or range of loss.
PJM Underfunding FTR Complaint
On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets.Underfunding of the FTR contracts resulted in losses of approximately$35 million ($0.5 million - FES; $34.5 million - AE Supply) in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year are estimated to be approximately$11.5 million($11.4 million- FES;$0.1 million- AE Supply).
On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue.On March 2, 2012, FERC dismissed the complaint without prejudice, pending PJM's publication for stakeholder review and discussion, a report on the causes of the FTR underfunding and potential improvements, including modeling, which could be made to minimize the revenue inadequacy. On March 30, 2012, FES and AE Supply requested rehearing and reconsideration of the March 2, 2012 order.On July 19, 2012, FERC issued its Order on Rehearing and again dismissed FirstEnergy's complaint without prejudice. FERC noted PJM's ongoing stakeholder process and directed that if the issues were not addressed in that process FirstEnergy could file its complaint again.
FTR Allocation Complaint
On March 26, 2012, FES and AE Supply filed a complaint with FERC against PJM challenging PJM's FTR allocation rules. PJM allocates FTRs to load-serving entities in an annual allocation process, up to each LSE's peak load, based on the expected transmission capability for the upcoming planning year. If a transmission facility is scheduled to be out of service for a significant part of the year, it can result in LSEs' FTR allocations being reduced in the annual allocation. When these transmission facilities return to service during the year, PJM will create monthly FTRs to reflect the increased transmission capability during that month. However, instead of allocating these new monthly FTRs to the LSEs that were unable to obtain their full allocation of FTRs in the annual allocation process, PJM's rules instead require PJM to auction off these new monthly FTRs in the market. The complaint seeks a change to the PJM rules such that the new FTRs created each month by transmission lines returning to service would first be allocated to those LSEs that were denied a full allocation of their FTR entitlement in the annual allocation process before they are auctioned off in the market. On April 16, 2012, PJM filed its answer to the complaint. Exelon Corporation filed a protest, and several other parties filed comments.On July 11, 2012, FERC issued its Order Granting Complaint and Requiring a Compliance Filing. In the order, FERC agreed with FirstEnergy's description of the issues and with FirstEnergy's proposed changes to PJM's rules, and FERC directed PJM to submit a compliance filing within 60 days to implement the changes in the rules.
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)CDWR during 2001. The settlement proposal claims that CDWR is owed approximately $190$190 millionfor these alleged overcharges. This proposal was made in the context of mediation efforts by 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 remandedoneof those proceedings to FERC, which arises out
of claims previously filed with 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 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. On May 4, 2011, FERC affirmed the judge’sjudge's ruling. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order.By Order issued June 13, 2012, FERC denied the request for rehearing. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals.
In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with 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 including AE Supply in this newadditional complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order.By Order issued June 13, 2012, that request for rehearing also was denied. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals. FirstEnergy cannot predict the outcome of this matter.either of the above matters or estimate the possible loss or range of loss.
PATH Transmission ExpansionProject
TrAIL Project.TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.
PATH Project.The PATH Project is comprised of a765kV transmission line that was 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. 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 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 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, affiliatesThe PJM Board has directed the PJM staff to perform additional analysis using the 2012 RTEP assumptions and incorporating the results of FirstEnergy and AEP filed motions or noticesthe May 2012 RPM base residual auction. The PJM staff is expected to withdrawreport its conclusions from this analysis to the Transmission Expansion Advisory Committee on August 9, 2012. All applications for authorization to construct the project that were pending beforefiled with state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. have been withdrawn.
Yards Creek
The WVPSC and VSCC have granted the motions 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 the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a 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 settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.
Seneca Pumped Storage Project Relicensing
The Seneca (Kinzua)Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. FERC issued a license for authorization to operate the project. The existing license expires on February 28, 2013.
In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the five-year ILP licensure process. FirstEnergy expects FERC to issue the new license before February 28, 2013. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.
Seneca
The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’sFERC's regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD)related documents in the license docket.
On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PADrelated documents necessary for themthe Seneca Nation to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’"competing application" to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.
The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps.Corps of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’sFirstEnergy's petition, including motions to dismiss FirstEnergy’sFirstEnergy's petition. The “project boundary” issue is pending before FERC.
The next steps in the relicensing process are for
On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to definea finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and perform certain environmentalother parties about the data set, methodology and operational studies to support their respective applications. These steps are expected to runmodeling of the hydrological impacts of project operations.In March of 2012, FirstEnergy hosted a meeting as part of the consultation process. In that meeting, FirstEnergy reviewed its proposed methodology for conducting the hydrological impacts study and answered questions from third parties about the methodology. On April 11, 2012, the Seneca Nation and other parties filed comments on the proposed hydrologic impacts study.The study processes, including the discrete hydrological impacts study, will extend through approximately November of 2013.
FirstEnergy cannot predict the outcome of these proceedingsthis matter or estimate the possible loss or range of loss.
MISO Capacity Portability
On June 11, 2012, the FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO Stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. Comments are due on August 10, 2012, and reply comments are due on August 27, 2012. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including the prices at this time.which those auctions would clear. FirstEnergy anticipates submitting initial comments by August 10, 2012 and, depending on the comments submitted by other parties, submitting reply comments by August 27, 2012.
Environmental MattersENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’sFirstEnergy's earnings and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations.
CAA Compliance
FirstEnergy is required to meet federally-approved SO2and NOx emissions regulations under the CAA. FirstEnergy complies with SO2and 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-emittinglower or non-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.
In July 2008,threecomplaints representing multiple plaintiffs were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant air emissions. Plant.Twoof these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,manner.” one being aOne complaint was filed on behalf oftwenty-oneindividuals and the other beingis a class action complaint seeking certification as a class action with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.
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TheIn December 2007, the states of New Jersey and Connecticut filed CAA citizen suits in 2007the U.S. District Court for the Eastern District of Pennsylvania alleging NSR violations at the coal-fired Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-EdME in 1999) and Met-Ed.ME. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’sCAA's PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, theThe Court granted Met-Ed’s motion to dismissdismissed New Jersey’sJersey's and Connecticut’sConnecticut's claims for injunctive relief against Met-Ed,ME, but denied Met-Ed’sME's motion to dismiss the claims for civil penalties. The parties dispute the scope of Met-Ed’sME's indemnity obligation to and from Sithe Energy,Energy. In February 2012, GenOn announced its plans to retire the Portland Station in January 2015 citing EPA emissions limits and Met-Edcompliance schedules to reduce SO2air emissions by approximately81%at the Portland Station by January 6, 2015.On July 27, 2012, FirstEnergy filed a motion for summary judgment arguing the Plaintiff's remaining claims for civil penalties are barred by the statute of limitations. FirstEnergy is unable to predict the outcome of this matter.matter or estimate the possible loss or range of loss.
In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland coal-fired plant Generation Station
based on “modifications” dating back to 1986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed,ME, JCP&L as the former owner of 16.67% of Keystone, and Penelec,PN, as former owner and operatorowners of Shawville,the facilities, are unable to predict the outcome of this matter.matter or estimate the possible loss or range of loss.
In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV.
In January 2011, the U.S. DOJ filed a complaint against PenelecPN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PenelecPN based on alleged “modifications” at the coal-fired Homer City generating plant between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’sCAA's PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation,NYSEG, and various current owners of Homer City, 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 Homer City’s air emissions as well as certification as a class action and to enjoin Homer City 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 Statesstates of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec,In October 2011, the co-owner and operator of Homer City prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to DismissCourt dismissed all of the federal claims with prejudice of the U.S. and the various state claims. ResponsiveCommonwealth of Pennsylvania and Reply briefs werethe states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth of Pennsylvania and the states of New Jersey and New York all filed on May 26, 2011notices appealing to the Third Circuit Court of Appeals. PN believes the claims are without merit and June 17, 2011, respectively. The scope of Penelec’s indemnity obligationintends to and from Mission is under dispute and Penelecdefend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter.matter or estimate the loss or possible range of loss. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.
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 coal-fired plants. The EPA’sEPA's NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. 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.matter or estimate the possible loss or range of loss.
In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation unitsunits: Albright, Armstrong, Fort Martin, Harrison, Hatfield’sHatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standardsprovisions under the CAA, which can require the installation of additional air emission control equipment when thea major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.
In May 2004,September 2007, AE AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604NOV from the Attorneys General of New York, New JerseyEPA alleging NSR and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions ofviolations under the CAA, as well as Pennsylvania and West Virginia state laws at the following West Virginia coal-fired plants: 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’sHatfield's Ferry and Mitchell coal-firedArmstrong plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MPcoal-fired Fort Martin and WP received a separate NoticeWillow Island plants in West Virginia. On June 29, 2012, EPA issued another CAA section 114 request for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. FirstEnergy intends to vigorously defend against these CAA matters, but cannot predict their outcomes or estimate the possible loss or range of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.loss.
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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 StatesU.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’scoal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A 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 Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants 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 coal-fired plant for NOX, SO2 and mercury, based on a PJM declaration that the plant 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 or estimate the possible loss or range of this matter.loss.
In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.
National Ambient Air Quality Standards
The EPA’sEPA's CAIR requires reductions of NOx and SO2emissions intwophases (2009/2010 and 2015), ultimately capping SO2 SO2emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacateddecided that CAIR “in its entirety” and directedviolated the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling andCAA but allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOx SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the “8-hour” ozone NAAQS.Court's decision. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR)CSAPR, to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the Federal Register). CSAPR requiresrequiring reductions of NOx and SO2 SO2emissions intwophases (2012 and 2014), ultimately capping SO2 SO2emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO2emission allowances between power plants located in the same state and interstate trading of NOx and SO2emission allowances with some restrictions. FGCO’sOn June 12, 2012, the EPA revised certain CSAPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO2emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO2emission allowances.On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy’sFirstEnergy's operations may result. Management is currently assessing the impact of CSAPR, other environmental proposals and other factors on FirstEnergy’s competitive fossil generating facilities, including but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operations of its coal-fired plants.
Hazardous Air Pollutant Emissions
On March 16,December 21, 2011, the EPA released its MACT proposal to establishfinalized the MATS imposing emission standardslimits for mercury, hydrochloric acidPM, and various metalsHCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the deactivation by September 1, 2012 (subject to a reliability review by PJM) ofninecoal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349MW (generating, on average, approximatelytenpercent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations.MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS.Depending on the action taken by the EPAoutcome of these proceedings and how any future regulationsthe MATS are ultimately implemented, FirstEnergy’sFirstEnergy's future cost of compliance with MACT regulations mayMATS is estimated to be substantial $975 millionand other changes to FirstEnergy’sFirstEnergy's operations may result.
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On March 8, 2012, FGCO filed an application for a feasibility study with PJM to install and interconnect to the transmission system832megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. However, when these units did not clear the May PJM capacity auction, the decision was made to not proceed with the project at this time. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant deactivations and requested RMR arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.On July 10, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. On July 16, 2012, FGCO and ATSI filed an application with FERC for authorization to transfer from FGCO to ATSI certain assets associated with Eastlake Units 1-5 and Lakeshore Unit 18 for conversion to synchronous condensers by ATSI for transmission reliability purposes as directed by PJM. Upon FERC approval, it is expected that the assets will be transferred in staggered closings when the units are no longer needed for RMR purposes. During the three months and six months ended June 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately$10 million($6 million by FES) and $17 million ($10 million by FES), respectively, as a result of the deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.
On March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.
Climate Change
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, 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 and report GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011.2010. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’sEPA'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 programpreconstruction permits would be required. The EPA establishedrequired including an emissions applicability threshold of75,000tons per year (tpy) of carbon dioxide CO2equivalents (CO2) effective January 2, 2011 for existing facilities under the CAA’sCAA'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 that recognized the scientific view that the increase in global temperature should be belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching $30$30 billionover the next three years with a goal of increasing to $100$100 billionby 2020; and establishes the “Copenhagen Green“Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To 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. A December 2011 U.N. Climate Change Conference in Durban, South Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.
In 2009, the U.S. Court of Appeals for the Second Circuit and the U.S. Court of Appeals for the Fifth Circuit reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO2emissions 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-CO2emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water ActCWA and its amendments, apply to FirstEnergy’sFirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’sFirstEnergy's operations.
In 2004, the EPA established new performance standards under Section 316(b) of the Clean Water ActCWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility’sfacility's cooling water system). In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’sCircuit's opinion and decided that Section 316(b) of the Clean Water ActCWA authorizes the EPA to compare costs with
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benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiringCWA to reduce fish impingement to be reduced to a12%annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. Onlife following studies to be provided to permitting authorities. In July 19, 2011,2012, the EPA extended the public comment period for finalizing the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remainswas extendedto July 27, 2012. 2013.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’splant's water intake channel to divert fish away from the plant’splant's water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore 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’sEPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
In April 2011, the U.S. Attorney’sAttorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the Clean Water ActCWA 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 toOn June 5, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil enforcement andliability claims for those petroleum spills toJanuary 31, 2013. FGCO is unabledoes not anticipate any losses resulting from this matter to predict the outcome of this matter.be material.
In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.
FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.
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’scoal-fired Hatfield's Ferry coal-fired plant.Plant. These criteria are reflected in the current PA DEPNPDES water discharge permit issued by PA DEP for that project. In January 2009, AE Supply appealed the PA DEP’sDEP's permitting decision which would require it to incur significantthe EHB, due to estimated costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150$150 million in order to install technology to meet the TDS and sulfate limits in the NPDES permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council which seeksalso appealed the NPDES permit seeking to impose more stringent technology-based effluent limitations. Those sameIn April 2012, a joint motion was filed by the parties have intervenedinforming the EHB of a proposed settlement and seeking the lifting of a portion of the EHB's stay of certain terms of the Hatfield's Ferry Plant's NPDES permit. The joint motion was granted by the EHB on April 27, 2012.The proposed settlement, in the appeal filedform of a Consent Decree, was lodged with the Commonwealth Court of Pennsylvania and published in the June 23, 2012, Pennsylvania Bulletin for a 30-day public comment period. The Consent Decree, if entered by AE Supply,the Commonwealth Court of Pennsylvania, will resolve the disputes concerning the Hatfield's Ferry Plant NPDES permit, including TDS 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 in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.sulphate limits.
In a parallel rulemaking, the
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 would apply only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.
In
In December 2010, PA DEP submitted its Clean Water ActCWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’sDEP's recommended sulfate impairment designation. PA DEP’sDEP's goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant
costs to reduce sulfate discharges into the Monongahela River from its Hatfield’sthe coal-fired Hatfield's Ferry and Mitchell facilitiesPlants in Pennsylvania and itsthe coal-fired Fort Martin facilityPlant in West Virginia.
In October 2009, the WVDEP issued thean NPDES 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 permitPlant, which imposes TDS, sulfate concentrations and other 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.as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order that setssetting deadlines for MP to meet certain of the effluent limits that arewere effective immediately under the terms of the NPDES permit. MP has appealed, the Fort Martin permit and the administrative order. The appeal included a request to stay certain of thecertain conditions of the NPDES permit and order while the appeal is pending, which washave been granted pending a final decision on the 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 NPDES permit wouldcould 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’sHatfield'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.limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.appeals or estimate the possible loss or range of loss.
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In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit in the U.S. District Court for the Northern District of West Virginia alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a 60-day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant. MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. In April 2012, the parties reached a settlement to resolve these CWA citizen suit claims for an immaterial amount. If approved by the Court, a Consent Decree will be entered by the Court to resolve these claims. MP is currently seeking relief from the arsenic limits through WVDEP agency review.
FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.
Regulation of Waste Disposal
Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’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 whether they should be regulated as hazardous or non-hazardous waste.
In December 2009, in an advancedadvance notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposedtwooptions for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’sEPA's hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’sOn July 27, 2012, the PA DEP filed a complaint against FGCO in the U.S. District Court for the Western District of Pennsylvania with claims under the Resource Conservation and Recovery Act and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FGCO to resolve those claims. The Consent Decree will be published to allow for a 30-day public comment period and requires FGCO to conduct monitoring, studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. BMP is pursuing several options for disposal of CCB following December 31, 2016.
FirstEnergy's future cost of compliance with any coal combustion residuals regulations that 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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.
The Little Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out
Certain of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.
The Utility Registrantsour utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980.CERCLA. 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 ofJune 30, 2011,2012, based on estimates of the total costs of cleanup, the Utility Registrants’FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately $133$122 million (JCP&L — $69(including$86 million TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $61 million)applicable to JCP&L) have been accrued throughJune 30, 2011. 2012. Included in the total are accrued liabilities of approximately $63$79 millionfor 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. On July 11, 2011, FirstEnergy wasor its subsidiaries could be found to be a potentially responsible party under CERCLA indirectly liable for a portionadditional amounts or additional sites, but the possible losses or range of past and future clean-up costslosses cannot be determined or reasonably estimated at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.this time.
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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. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages. After various motions, rulings and appeals, the Plaintiffs’ claims for consumer fraud, common law fraud, negligent misrepresentation, strict product liability and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have yet to take any affirmative steps to pursue their individual claims.
Nuclear Plant Matters
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofJune 30, 2011,2012, FirstEnergy had approximately $2$2 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’sFirstEnergy's NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’sFirstEnergy's obligation to fund 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 NDT. The NRC issued guidance anticipating an increaseFirstEnergy Corp. currently maintains a $95 millionparental guaranty in low-level radioactive waste disposal costs associated withsupport of the decommissioning of 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. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.
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In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB)ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. ByThe NRC subsequently narrowed the scope of admitted contentions in this order,proceeding to a challenge to the computer code used to model source terms in FENOC's Severe Accident Mitigation Alternatives analysis. On January 10, 2012, intervenors petitioned the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1)for a combinationnew contention on the cracking of renewable energy sources as alternativesthe Davis-Besse shield building discussed below.The intervenors supplemented their petition for a contention on the shield building on multiple occasions. On July 9, 2012, the intervenors petitioned the ASLB for a new contention on the environmental impacts of temporary spent fuel storage at Davis-Besse due to the renewallack of Davis-Besse’s operating license,a repository and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearingdisposal of these wastes. The ASLB has yet to rule on the Davis-Besse license renewal application.admission of these latest requests for new contentions.
On April 14, 2011, a group of environmental organizations petitioned
Similarly, on June 18 and 19, 2012, the NRC Commissioners to suspend certain pending nuclear licensing proceedings, includingintervenors in the Davis-Besse license renewal proceeding to ensureand other petitioners requested that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and muchsuspends the issuance of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.
In January 2004, subsidiaries of FirstEnergy filed a lawsuitfinal decisions in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilitiesall pending reactor licensing proceedings as a result of the DOE failuredecision in the case of State of New York v. NRC, No. 11-1045. (D.C. Cir. June 8, 2012). In this case, the D.C. Circuit vacated the NRC's updated Waste Confidence Decision and its Temporary Storage Rule and remanded those rulemakings to begin accepting spentthe NRC for further consideration. FENOC and other Licensees opposed the suspension request. By order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the D.C. Circuit decision and all pending contentions on this topic should be held in abeyance until further order. The NRC also directed that all licensing reviews and proceedings should continue to move forward.
On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.
On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC, including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.On June 21, 2012, the NRC issued an Inspection Report that concluded that FENOC established a sufficient basis for the causes of the shield building laminar cracking.
By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear fuel on January 31, 1998. DOE was requiredreactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to so commence accepting spent nuclear fueldetermine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence. Additional adverse findings by the Nuclear Waste Policy Act (42 USC 10101 et seq)NRC could result in further inspection activities.
On March 12, 2012, the NRC issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the contracts entered intolatest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi
are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.
On February 16, 2012, the NRC issued a request for information to the licensed operators of11nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in higher burn up fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the DOEfuel manufacturer and that the owners and operators of these facilities pursuantNRC might consider imposing restrictions on reactor operating limits.On March 16, 2012, FENOC submitted its response to the Act. On January 18, 2011,NRC demonstrating that the parties, FirstEnergy and DOJ, filed a joint status reportNRC requirements are being met. FENOC also agreed to submit to the NRC revised large break loss of coolant accident analyses by December 15, 2016, that established a schedule forfurther consider the litigationeffects of these claims. FirstEnergy filed 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 review and audit by DOE.fuel pellet thermal conductivity degradation.
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),ICG, Anker West Virginia Mining Company, Inc. (Anker WV),WV, and Anker Coal Group, Inc. (Anker Coal).Coal. Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. 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’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 from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80$80 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150$150 millionfor future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104$104 million ($($90 millionin future damages and $14$14 million for replacement coal / interest). Post-trial filings occurred inOn August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 with Oral Argumentverdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal.Briefing on June 28, 2011. The parties expect a ruling sometimethe Appeal has concluded and an oral argument was held on May 16, 2012. A decision from the Appellate court is expected in the thirdfourth quarter at which time the judgment will be final. The parties have 30 days to appeal the final judgment.of 2012. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.appeal.
Other Legal Matters
In February 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 washad been approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas.jurisdiction. The court granted the motion to dismiss on September 7, 2010. Theand the plaintiffs appealed the decision to the Court of Appeals of Ohio. The Court of Appeals affirmed the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud which it remanded to the trial court. The Companies timely filed a notice of appeal with the Supreme Court of Ohio which has not yet rendered anon December 5, 2011, challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio agreed to hear the appeal.
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There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’sFirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.under Note 8, Regulatory Matters to the Combined Notes to the Consolidated Financial Statements.
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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced 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
See Note 12 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.105
130
FIRSTENERGY SOLUTIONS CORP.
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services to wholesale and retail customers, and through its principal subsidiaries, FGCO and NGC, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generation facilities, respectively.facilities. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, the uncommitted output of AE Supply, 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, and pursuant to full output, cost-of-service PSAs.
FES’ revenues are derived from sales to individual retail customers, sales to communitiescustomers in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan, New Jersey and New Jersey. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.Maryland.
The demand for electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markets, global economic activity as well as economic activity and weather conditions in the Midwest and Mid-Atlantic regions and weather conditions.of the United States.
For additional information with respect to FES, 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: Overview, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk Outlook and New Accounting Standards and Interpretations.Outlook.
Results of Operations
Net income decreasedincreased by $158$47 million in the first six months of 20112012 compared to the same period of 2010. The decrease was primarily due to lower sales margin, an inventory reserve adjustment, non-core asset impairments and the effect of mark-to-market adjustments.2011, as more fully described below.
Revenues -
Total revenues decreased $30increased $288 million, or 1%11%, in the first six months of 2011,2012, compared to the same period of 2010,2011, primarily due to reduced POLR and structured sales, partially offset by growth in direct and governmental aggregation sales and wholesale sales partially offset by a net decline in POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the first six months of 2011.
The decreaseincrease in total revenues resulted from the following sources:
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| Revenues by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In millions) | |
| Direct and Governmental Aggregation | | $ | 1,765 | | | $ | 1,097 | | | $ | 668 | |
| POLR and Structured Sales | | | 607 | | | | 1,315 | | | | (708 | ) |
| Wholesale | | | 156 | | | | 142 | | | | 14 | |
| Transmission | | | 56 | | | | 36 | | | | 20 | |
| RECs | | | 44 | | | | 67 | | | | (23 | ) |
| Other | | | 56 | | | | 57 | | | | (1 | ) |
| | | | | | | | | | |
Total Revenues | | $ | 2,684 | | | $ | 2,714 | | | $ | (30 | ) |
| | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Six Months | | | | |
| | | Ended June 30 | | | Increase | |
| MWH Sales by Type of Service | | 2011 | | | 2010 | | | (Decrease) | |
| | | (In thousands) | | | | | |
| Direct | | | 21,219 | | | | 12,857 | | | | 65.0 | % |
| Governmental Aggregation | | | 8,279 | | | | 5,447 | | | | 52.0 | % |
| POLR and Structured Sales | | | 9,561 | | | | 25,344 | | | | (62.3 | )% |
| Wholesale | | | 1,380 | | | | 1,538 | | | | (10.3 | )% |
| | | | | | | | | | |
Total Sales | | | 40,439 | | | | 45,186 | | | | (10.5 | )% |
| | | | | | | | | | |
|
| | | | | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| Revenues by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In millions) |
| Direct and Governmental Aggregation | | $ | 2,040 |
| | $ | 1,765 |
| | $ | 275 |
|
| POLR and Structured Sales | | 426 |
| | 607 |
| | (181 | ) |
| Wholesale | | 387 |
| | 156 |
| | 231 |
|
| Transmission | | 60 |
| | 56 |
| | 4 |
|
| RECs | | 5 |
| | 44 |
| | (39 | ) |
| Other | | 54 |
| | 56 |
| | (2 | ) |
| Total Revenues | | $ | 2,972 |
| | $ | 2,684 |
| | $ | 288 |
|
131
|
| | | | | | | | | |
| | | Six Months
Ended June 30 | | Increase |
| MWH Sales by Type of Service | | 2012 | | 2011 | | (Decrease) |
| | | (In thousands) | | |
| Direct | | 25,954 |
| | 21,219 |
| | 22.3 | % |
| Governmental Aggregation | | 9,930 |
| | 8,279 |
| | 19.9 | % |
| POLR and Structured Sales | | 7,645 |
| | 9,561 |
| | (20.0 | )% |
| Wholesale | | 86 |
| | 1,380 |
| | (93.8 | )% |
| Total MWH Sales | | 43,615 |
| | 40,439 |
| | 7.9 | % |
The increase in combined direct and governmental aggregation revenues of $668$275 million resulted from the acquisition of new residential, commercial and industrial customers. Sales were provided to approximately 2.0 million residential, commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio that provided generation to approximately 1.5 million residential and small commercial customers at the end of June 20112012, compared to approximately 1.11.7 million as of June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation customers at the end of June 2010.given declining electric market prices.
The decrease in combined POLR and structured revenues of $708$181 million was due primarily to lower sales volumes to Met-Ed and Penelec, primarily due to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec, and reduced sales to the Ohio Companies, ME and PN. Revenues were also adversely impacted by lower unit prices which were partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participationstructured sales. The decline in POLR auctions and RFPs are expected to continue but the proportion of these sales will dependreflects our continued focus on our hedge positions for direct retail and aggregation sales.other sales channels.
Wholesale revenues increased by $14increased $231 million due to higher wholesale pricesincreased gains of $228 million on financially settled contracts and a $42 million increase in capacity revenues. These increases were partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by generating units were partially offset by losses on financially settled sales.sold.
The following tables summarize the price and volume factors contributing to changes in revenues:
| | | | | |
| | | Increase | |
| Source of Change in Direct and Governmental Aggregation | | (Decrease) | |
| | | (In millions) | |
| Direct Sales: | | | | |
| Effect of increase in sales volumes | | $ | 493 | |
| Change in prices | | | (20 | ) |
| | | | |
| | | | 473 | |
| | | | |
| | | | | |
| Governmental Aggregation: | | | | |
| Effect of increase in sales volumes | | | 176 | |
| Change in prices | | | 19 | |
| | | | |
| | | | 195 | |
| | | | |
Net Increase in Direct and Governmental Aggregation Revenues | | $ | 668 | |
| | | | |
| | | | | |
| | | Increase | |
| Source of Change in POLR Revenues | | (Decrease) | |
| | | (In millions) | |
| POLR: | | | | |
| Effect of decrease in sales volumes | | $ | (819 | ) |
| Change in prices | | | 111 | |
| | | | |
| | | $ | (708 | ) |
| | | | |
|
| | | | |
| Source of Change in Direct and Governmental Aggregation | | Increase (Decrease) |
| | | (In millions) |
| Direct and Governmental Aggregation: | | |
| Effect of increase in sales volumes | | $ | 381 |
|
| Change in prices | | (106 | ) |
| | | $ | 275 |
|
| | | | | |
| | | Increase | |
| Source of Change in Wholesale Revenues | | (Decrease) | |
| Wholesale: | | | | |
| Effect of increase in sales volumes | | $ | (15 | ) |
| Change in prices | | | 29 | |
| | | | |
| | | $ | 14 | |
| | | | |
Transmission revenues |
| | | | |
| Source of Change in POLR and Structured Revenues | | Increase (Decrease) |
| | | (In millions) |
| POLR and Structured: | | |
| Effect of decrease in sales volumes | | $ | (122 | ) |
| Change in prices | | (59 | ) |
| | | $ | (181 | ) |
|
| | | | |
| Source of Change in Wholesale Revenues | | Increase (Decrease) |
| | | (In millions) |
| Wholesale: | | |
| Effect of decrease in sales volumes | | $ | (39 | ) |
| Gain on settled contracts | | 228 |
|
| Capacity revenue | | 42 |
|
| | | $ | 231 |
|
Operating Expenses -
Total operating expenses increased by $20$220 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined $23 million in the first six months of 2011.
Expenses
Total operating expenses increased by $199 million in the first six months of 2011,2012 compared with the same period of 2010.2011.
132
The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2011,2012 compared with the same period last year:
| | | | | |
| | | Increase | |
| Source of Change in Fuel and Purchased Power | | (Decrease) | |
| | | (In millions) | |
| Fossil Fuel: | | | | |
| Change due to increased unit costs | | $ | 2 | |
| Change due to volume consumed | | | (29 | ) |
| | | | |
| | | | (27 | ) |
| | | | |
| | | | | |
| Nuclear Fuel: | | | | |
| Change due to increased unit costs | | | 14 | |
| Change due to volume consumed | | | 1 | |
| | | | |
| | | | 15 | |
| | | | |
| | | | | |
| Non-affiliated Purchased Power: | | | | |
| Change due to increased unit costs | | | 108 | |
| Change due to volume purchased | | | (242 | ) |
| | | | |
| | | | (134 | ) |
| | | | |
| | | | | |
| Affiliated Purchased Power: | | | | |
| Change due to increased unit costs | | | 34 | |
| Change due to volume purchased | | | (30 | ) |
| | | | |
| | | | 4 | |
| | | | |
Net Decrease in Fuel and Purchased Power Costs | | $ | (142 | ) |
| | | | |
Total fuel |
| | | |
| Source of Change in Fuel and Purchased Power | Increase (Decrease) |
| | (In millions) |
| Fossil Fuel: | |
| Change due to increased unit costs | $ | 22 |
|
| Change due to volume consumed | (13 | ) |
| | 9 |
|
| | |
| Nuclear Fuel: | |
| Change due to increased unit costs | 1 |
|
| Change due to volume consumed | 6 |
|
| | 7 |
|
| | |
| Non-affiliated Purchased Power: | |
| Change due to decreased unit costs | (142 | ) |
| Change due to volume purchased | 147 |
|
| Loss on settled contracts | 229 |
|
| Capacity expense | 61 |
|
| | 295 |
|
| | |
| Affiliated Purchased Power: | |
| Change due to decreased unit costs | (53 | ) |
| Change due to volume purchased | 41 |
|
| Loss on settled contracts | 128 |
|
| | 116 |
|
| Net Increase in Fuel and Purchased Power Costs | $ | 427 |
|
The increase in purchased power volumes primarily relates to the overall increase in sales volumes and economic purchases.
Other operating expenses decreased by $190 million in the first six months of 2012, compared to the first six months of 2011 due to the following:
Transmission expenses decreased $89 million due primarily to lower congestion, network and line loss costs, partially offset by higher ancillary costs.
Nuclear operating costs decreased by $12$8 million due primarily to lower labor and materials and equipment costs. During the first six months of 2012, there were refueling outages at Davis Besse and Beaver Valley Unit 1 compared to the first six months of 2011, which included refueling outages at Perry and Beaver Valley Unit 2. Total outage days were reduced in the first six months of 2011,2012 compared to the same period of 2010, as2011.
Fossil operating costs decreased by $16 million due primarily to lower contractor and materials and equipment costs resulting from a result of reduced generation at the fossil units,decrease in planned and unplanned outages, partially offset by higher fossil unit costs. Fossil unit prices increased primarily due to increased coal transportation costs. Nuclear fuel expenses increased primarily due to higher unit prices following the refueling outages that occurred in 2010.
Non-affiliated purchased powerseverance costs decreased by $134 million in the first six months of 2011, compared to the same period of 2010, due to lower volumes purchased partially offset by higher unit costs. The decrease in volume relates to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec in the first half of 2011. Affiliated purchased power costs increased by $4 million in the first six months of 2011, comparedcertain fossil units to the same period of 2010, due to higher unit costs, partially offset by decreased volumes purchased.be deactivated.
Other operating expenses increaseddecreased by $302$77 million in the first six months of 2011, compared to the same period of 2010primarily due to the following:
Transmissionfavorable mark-to-market adjustments on commodity contract positions ($64 million). In addition, 2011 expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $22 million.
Nuclear operating costs increased by $48 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse hadincluded a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.
Fossil operating costs increased by $20 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.
A $54 million provision for excess and obsolete material relatedrelating to revised inventory practices adopted in connection with the Allegheny merger.
These decreases were partially offset by increases of $41 million for labor, agent fees, professional and contractor services and costs associated with our retail business.Impairment charges ofon long-lived assets decreased by $20 million due to a 2011 charge related to peaking facilities that were subsequently sold in 2011.
General taxes increased by $9 million due to an increase in revenue-related taxes.
Depreciation expense decreased by $6 million primarily due to a lower asset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain
fossil assets and credits resulting from a settlement with the DOE regarding storage of spent nuclear fuel.
Other Expense -
Total other expense decreased by $19 million in the first six months of 2012, compared to the same period of 2011, primarily due to lower net interest expense of $13 million resulting from debt reductions in 2011 and credits related to the settlement with the DOE noted above. Non-operating income increased by $18$16 million due primarily to impairments at certain non-core peaking facilitiesadditional proceeds on 2011 asset sales that were earned during the first six months of 2011.
General taxes increased by $11 million due to an increase in revenue-related taxes.
Other Expense
Total other expense increased by $17 million in the first six months of 2011, compared to the same period of 2010, primarily due to a decrease in capitalized interest ($24 million) associated with the completion of the Sammis AQC project in 2010,2012, and was partially offset by increasedlower investment income ($810 million) from higher NDT income.on the NDTs.
133
OHIO EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy.FE. OE engages in the distribution and sale of electric energy to customers in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, by providing regulated electric distribution services. OE procures generation services for those franchisetheir customers electing to retainas well as generation procurement services for customers who have not selected an alternative supplier. The areas served by OE and Penn as their power supplier.have populations of approximately 2.3 million and 0.4 million, respectively.
For additional information with respect to OE, please see the information contained in FirstEnergy’sFE’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Overview, Results of Operations - Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk Outlook and New Accounting Standards and Interpretations.Outlook.
Results of Operations
Earnings available to parent decreasedNet income decreased by $5$1 million in during the first six months of 2011,2012, compared to the same period of 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs and amortization of regulatory assets.
Revenues2011, as more fully described below.
Revenues decreased-
Revenues decreased by $171$3 million or 18%, in the first six months of 2011,2012, compared with the same period in 2010,of 2011, due to a decrease in generation revenues, partially offset by higher distribution and wholesaleretail generation revenues.
Distribution revenues increaseddecreased by $31$1 million in the first six months of 2011,2012, compared to the same period in 2010,of 2011, due to an increase in KWHlower MWH deliveries into the residential and commercial customer classes, partially offset by higher MWH deliveries to the industrial sectors and higher average prices in all customer classes. The higher KWHclass. Reduced deliveries into the residential classand commercial classes were driven by increasedlower weather-related usage and declining average customer consumption. Average prices for residential customers were relatively unchanged as the implementation of Ohio's Rider NMB in June 2011, which recovers non-market based charges from PJM, including network integration transmission service charges, were offset by the first six monthssuspension of 2011, reflecting a 6% increaseOhio's deferred cost recovery rider in heating degree days.December 2011. The increase in distribution deliveries to industrial customers was primarilyprincipally due to recoveringimproving economic conditions in OE’s and Penn’s service territory. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.territories.
Changes in distribution KWHMWH deliveries and revenues in the first six months of 2011,2012, compared to the same period in 2010,of 2011, are summarized in the following tables:
|
| | | | |
Distribution KWHMWH Deliveries | | Increase | (Decrease) |
| | | | |
| Residential | | (4.5 | 3.0 | )% |
| Commercial | | (0.3 | 0.2 | )% |
| Industrial | | 6.3 | 3.5 | % |
| | | |
Net Increase in Distribution MWH Deliveries | | | 2.4 | % |
| 0.3 | | | % |
| | | | | |
| Distribution Revenues | | Increase | |
| | | (In millions) | |
| Residential | | $ | 19 | |
| Commercial | | | 7 | |
| Industrial | | | 5 | |
| | | | |
Increase in Distribution Revenues | | $ | 31 | |
| | | | |
|
| | | | |
| Distribution Revenues | | Increase (Decrease) |
| | | (In millions) |
| Residential | | $ | (12 | ) |
| Commercial | | 5 |
|
| Industrial | | 6 |
|
| Net Decrease in Distribution Revenues | | $ | (1 | ) |
Retail generation revenues decreased by $211 million primarily due to a decrease in KWH sales and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE defersand Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWHRetail generation revenues decreased by $1 million primarily due to reduced MWH sales were primarily the result offrom increased customer shopping, partially offset by increasedhigher average prices in the residential customer class. Lower MWH sales were primarily due to lower weather-related usage in the first six months of resulting from heating degree days that were 22% below 2011 levels, declining average customer consumption, reduced residential accounts as described above. Thewell as an increase in customer shopping levels to 73% compared to 69% in the same quarter of last year. Higher average prices for residential commercial and industrial customer classes was 23%, 14% and 8%, respectively.customers were primarily due to the recovery of residential generation credits for electric heating discounts, which began in September 2011.
134
Changes in retail generation KWHMWH sales and revenues in the first six months of 2011,2012, compared to the same period in 2010,of 2011, are summarized in the following tables:
|
| | | | |
Retail Generation KWHMWH Sales | | Decrease | |
| | | | |
| Residential | | | (30.712.6 | )% |
| Commercial | | | (39.023.4 | )% |
| Industrial | | | (25.47.0 | )% |
| | | |
Decrease in Retail Generation Sales | | | (31.213.3 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (128 | ) |
| Commercial | | | (52 | ) |
| Industrial | | | (31 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (211 | ) |
| | | | |
|
| | | | |
| Retail Generation Revenues | | Increase (Decrease) |
| | | (In millions) |
| Residential | | $ | 30 |
|
| Commercial | | (22 | ) |
| Industrial | | (9 | ) |
| Net Decrease in Retail Generation Revenues | | $ | (1 | ) |
Wholesale generation revenues increaseddecreased by $15$4 million in the first six months of 2011,2012, compared to the same period of 2010,2011, due to higherlower revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.
Operating Expenses -
Total operating expenses decreaseddecreased by $171$6 million in the first six months of 2011,2012, compared to the same period of 2010.2011. The following table presents changes from the prior period by expense category:
| | | | | |
| | | Increase | |
| Expenses - Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (175 | ) |
| Other operating expenses | | | 36 | |
| Amortization of regulatory assets, net | | | (36 | ) |
| General taxes | | | 4 | |
| | | | |
Net Decrease in Expenses | | $ | (171 | ) |
| | | | |
|
| | | | |
| Operating Expenses - Changes | | Increase (Decrease) |
| | | (In millions) |
| Purchased power costs | | $ | (60 | ) |
| Other operating expenses | | 38 |
|
| Provision for depreciation | | 3 |
|
| Amortization of regulatory assets, net | | 12 |
|
| General taxes | | 1 |
|
| Net Decrease in Operating Expenses | | $ | (6 | ) |
Purchased power costs decreased in the first six months of 2011,2012, compared to the same period of 2010,2011, due to lower KWHMWH purchases resulting from reduced requirements from lower generation sales requirements in the first six months of 2011 coupled with lower unit costs.sales. The increase in other operating expenses for the first six months of 2012 compared to the same period of 2011, was principally due to expenses associated with refueling outages at OE’s leased Perrynetwork integration transmission service charges that, prior to June 2011, were incurred by generation suppliers, and Beaver Valley Unit 2 that were absent in 2010. The amortizationare being recovered through the Rider NMB discussed above. Amortization of regulatory assets, decreasednet, increased primarily due to higherlower deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.
Other Expense
Other2012. Provision for depreciation expense increased by $3 millionmainly due to an increase in the first six months of 2011, compared to the same period of 2010 due to lower nuclear decommissioning trust investment income.depreciable asset base.
135
JERSEY CENTRAL POWER & LIGHT COMPANY
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
CEIJCP&L is a wholly owned, electric utility subsidiary of FirstEnergy. CEIFE. JCP&L conducts business in northeastern Ohio,New Jersey by providing regulated electric transmission and distribution services. CEIservices in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. JCP&L procures generation services for thoseelectric supply to serve its BGS customers electing to retain CEI as their power supplier.through a statewide auction process approved by the NJBPU.
For additional information with respect to CEI,JCP&L, please see the information contained in FirstEnergy’sFE’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Regulatory Assets, 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 decreased slightly in the first six months of 2011, compared to the same period of 2010. The decrease in earnings was due to lower revenues, partially offset by lower purchased power and amortization of regulatory assets.
Revenues
Revenues decreased by $183 million, or 29%, in the first six months of 2011, compared to the same period of 2010, due to lower retail generation and distribution revenues.
Distribution revenues decreased by $14 million in the first six months of 2011, compared to the same period of 2010, due to lower average unit prices for the residential and industrial customer classes, partially offset by increased KWH deliveries to the residential and commercial customer classes. The lower average unit prices were the result of the absence of transition charges in 2011. Higher KWH deliveries to the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 15% increase in heating degree days in CEI’s service territory. Lower distribution deliveries to industrial customers reflected softer economic conditions in this sector.
Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 2.2 | % |
Commercial | | | 2.9 | % |
Industrial | | | (3.1 | )% |
| | | |
Increase in Distribution Deliveries
| | | 0.6 | % |
| | | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 2 | |
| Commercial | | | 17 | |
| Industrial | | | (33 | ) |
| | | | |
Net Decrease in Distribution Revenues | | $ | (14 | ) |
| | | | |
136
Retail generation revenues decreased by $169 million in the first six months of 2011, compared to the same period of 2010, primarily due to lower KWH sales in all customer classes and lower average unit prices for the commercial and residential customer classes. Customer shopping has increased for residential, commercial and industrial classes by 22%, 13% and 36%, respectively. 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 purchased power costs, resulting in no material effect to current period earnings. Reduced KWH sales were primarily the result of increased customer shopping in the first six months of 2011, partially offset by the impact of increased weather-related usage by residential customers as described above. Lower average unit prices in the residential customer class were the result of generation credits in place for 2011.
Decreases in retail generation sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
Retail Generation KWH Sales | | Decrease | |
| | | | |
Residential | | | (46.6 | )% |
Commercial | | | (44.2 | )% |
Industrial | | | (69.8 | )% |
| | | |
Decrease in Retail Generation Sales
| | | (55.0 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (69 | ) |
| Commercial | | | (46 | ) |
| Industrial | | | (54 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (169 | ) |
| | | | |
Expenses
Total expenses decreased by $173 million in the first six months of 2011, compared to the same period of 2010. The following table presents the change from the prior period by expense category:
| | | | | |
| | | Increase | |
| Expenses - Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (155 | ) |
| Other operating costs | | | 6 | |
| Amortization of regulatory assets, net | | | (34 | ) |
| General taxes | | | 10 | |
| | | | |
Net Decrease in Expenses | | $ | (173 | ) |
| | | | |
Purchased power costs decreased in the first six months of 2011 due to lower KWH purchases resulting from reduced sales requirements in the first six months of 2011. Other operating expenses increased principally due to 2011 inventory valuation adjustments. Decreased amortization of regulatory assets was primarily due to the completion of transition cost recovery at the end of 2010 and deferred residential generation credits in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased in the first six months of 2011 due to increased property taxes as compared to the same period of 2010.
137
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’s Management’s Discussion and Analysis of Financial Condition andOverview, Results of Operations under the following subheadings, which information is incorporated by reference herein: Regulatory Assets, 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 by $3 million in the first six months of 2011, compared to the same period of 2010. The increase primarily resulted from lower purchased power costs and higher cost deferrals, partially offset by lower revenues and higher other operating expenses.
Revenues
Revenues decreased by $40 million, or 16%, in the first six months of 2011, compared to the same period of 2010, due to a decrease in retail generation revenues, partially offset by higher distribution revenues and wholesale generation revenues.
Distribution revenues increased by $3 million in the first six months of 2011, compared to the same period of 2010, due to higher residential revenues, partially offset by lower industrial revenues. Residential revenues were the result of higher KWH deliveries and average unit prices. The higher KWH deliveries in the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 14% increase in heating degree days, partially offset by a 23% decrease in cooling degree days in TE’s service territory. Industrial revenues were impacted by lower average unit prices, partially offset by higher KWH deliveries from recovering economic conditions.
Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 4.5 | % |
Commercial | | | (2.5 | )% |
Industrial | | | 3.7 | % |
| | | |
Net Increase in Distribution Deliveries
| | | 2.6 | % |
| | | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 5 | |
| Commercial | | | — | |
| Industrial | | | (2 | ) |
| | | | |
Net Increase in Distribution Revenues | | $ | 3 | |
| | | | |
Retail generation revenues decreased by $53 million in the first six months of 2011, compared to the same period of 2010, due to lower KWH sales and lower unit prices for all customer classes. 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 purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were the result of increased customer shopping, partially offset by increased weather-related usage as described above. Customer shopping has increased for residential, commercial and industrial classes by 16%, 13% and 5%, respectively.
138
Decreases in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
Retail Generation KWH Sales | | Decrease | |
| | | | |
Residential | | | (28.3 | )% |
Commercial | | | (46.6 | )% |
Industrial | | | (11.7 | )% |
| | | |
Decrease in Retail Generation Sales
| | | (22.6 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (16 | ) |
| Commercial | | | (13 | ) |
| Industrial | | | (24 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (53 | ) |
| | | | |
Wholesale revenues increased by $9 million in the first six months of 2011, compared to the same period of 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.
Expenses
Total expenses decreased by $42 million in the first six months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:
| | | | | |
| | | Increase | |
| Expenses - Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (53 | ) |
| Other operating expenses | | | 18 | |
| Deferral of regulatory assets, net | | | (8 | ) |
| General Taxes | | | 1 | |
| | | | |
Net Decrease in Expenses | | $ | (42 | ) |
| | | | |
Purchased power costs decreased in the first six months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements in the first six months of 2011 coupled with lower unit costs. The increase in other operating costs for the first six months of 2011 was primarily due to expenses associated with the 2011 refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. The deferral of regulatory assets reduced expenses due to higher PUCO-approved cost deferrals in the first six months of 2011, compared to the same period of 2010.
Other Expense
Other expense increased by $2 million in the first six months of 2011, compared to the same period of 2010, due to lower nuclear decommissioning trust investment income.
139
JERSEY CENTRAL POWER & LIGHT COMPANY
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.
As authorized by JCP&L’s Board of Directors, on May 31, 2011 JCP&L returned $500 million of capital to FirstEnergy Corp., the sole owner of all of the shares of JCP&L’s common stock.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein:- Regulatory Assets, Capital Resources and Liquidity, Market Risk Information, Credit Risk Outlook and New Accounting Standards and Interpretations.Outlook.
Results of Operations
Net income decreaseddecreased by $18$3 million in the first six months of 2011,2012, compared to the same period of 2010. The 2011, as more fully described below.
Revenues
Revenues decrease was primarily due to lower revenues, partially offsetd by reductions in purchased power costs, other operating costs and net amortization of regulatory assets.
Revenues
Revenues decreased by $190$263 million, or 13%21%, in the first six months of 20112012, compared to the same period of 2010.2011. The decrease in revenues was due to lower distribution, and retail generation revenues, partially offset by an increase inand wholesale generation and other revenues.
Distribution revenues decreased by $71$81 million in the first six months of 2011,2012, compared to the same period of 2010,2011, primarily due to lower MWH deliveries and an NJBPU-approved rate adjustmentreduction that became effective March 1, 2011,2012, for all customer classes. The lower KWHLower MWH deliveries towere principally in the residential class, were influenced byreflecting decreased weather-related usage in the first six months of 2011, reflecting a 16% decrease in cooling degree days offsetting a 7% increase in heating degree days in JCP&L’s service territory. Lower distribution2012, partially offset by higher MWH deliveries to commercial and industrial customers reflected soft economic conditions in these sectors.customers.
DecreasesChanges in distribution KWHMWH deliveries and revenues in the first six months of 20112012 compared to the same period of 20102011 are summarized in the following tables:
|
| | | | |
Distribution KWHMWH Deliveries | | Decrease | Increase (Decrease) |
| | | | |
| Residential | | | (2.54.9 | )% |
| Commercial | | | (3.30.8 | )% |
| Industrial | | 2.2 | (1.8 | )% |
| | | |
Net Decrease in Distribution Deliveries | | | (2.72.2 | )% |
| | | |
| | | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (33 | ) |
| Commercial | | | (31 | ) |
| Industrial | | | (7 | ) |
| | | | |
Decrease in Distribution Revenues | | $ | (71 | ) |
| | | | |
Retail generation revenues decreased by $132 million due to lower retail generation KWH sales in all customer classes primarily due to an increase in customer shopping. Customer shopping has increased for residential, commercial and industrial classes by 10%, 11% and 4%, respectively. |
| | | | |
| Distribution Revenues | | Decrease |
| | | (In millions) |
| Residential | | $ | (41 | ) |
| Commercial | | (32 | ) |
| Industrial | | (8 | ) |
| Decrease in Distribution Revenues | | $ | (81 | ) |
Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect on earnings. Retail generation revenues decreased by $104 million due to currentlower retail generation MWH sales in all customer classes primarily due to lower weather-related usage and an increase in customer shopping levels to 50% in the first six months of 2012, compared to 43% in the same period earnings.of 2011.
140
Decreases in retail generation KWHMWH sales and revenues in the first six months of 2011,2012, compared to the same period of 2010,2011, are summarized in the following tables:
|
| | | | |
Retail Generation KWHMWH Sales | | Decrease | |
| | | | |
| Residential | | | (12.112.3 | )% |
| Commercial | | | (26.215.9 | )% |
| Industrial | | | (24.821.9 | )% |
| | | |
Decrease in Retail Generation Sales | | | (16.713.5 | )% |
| | | |
| | | | | |
| Retail Generation Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (68 | ) |
| Commercial | | | (59 | ) |
| Industrial | | | (5 | ) |
| | | | |
Decrease in Retail Generation Revenues | | $ | (132 | ) |
| | | | |
|
| | | | |
| Retail Generation Revenues | | Decrease |
| | | (In millions) |
| Residential | | $ | (69 | ) |
| Commercial | | (29 | ) |
| Industrial | | (6 | ) |
| Decrease in Retail Generation Revenues | | $ | (104 | ) |
Wholesale generation revenues increaseddecreased by $6$78 million in the first six months of 2011,2012, compared to the same period of 2010,2011, primarily due to an increasea decrease in PJM spot market energy sales.sales, reflecting less volume available for sale as a result of the expiration of a NUG contract in August 2011.
Other revenues increasedOperating Expenses
Total operating expenses decreased by $8$263 million in the first six months of 2011,2012, compared to the same period of 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues.
Expenses
Total expenses decreased by $163 million in the first six months of 2011 compared to the same period of 2010.. The following table presents changes from the prior period by expense category:
| | | | | |
| | | Increase | |
| Expenses - Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (126 | ) |
| Other operating costs | | | (6 | ) |
| Provision for depreciation | | | (3 | ) |
| Amortization of regulatory assets, net | | | (29 | ) |
| General taxes | | | 1 | |
| | | | |
Net Decrease in Expenses | | $ | (163 | ) |
| | | | |
|
| | | | |
| Operating Expenses - Changes | | Increase (Decrease) |
| | | (In millions) |
| Purchased power costs | | $ | (180 | ) |
| Other operating expenses | | 9 |
|
| Provision for depreciation | | 8 |
|
| Amortization of regulatory assets, net | | (94 | ) |
| General taxes | | (6 | ) |
| Net Decrease in Operating Expenses | | $ | (263 | ) |
Purchased power costs decreaseddecreased by $126$180 million in the first six months of 20112012 due to lower requirements from reduced retail generation sales. Other operating costs decreasedthe expiration of a NUG contract and a decrease in volumes required, as described above. This was partially offset by $6 millionthe completion of the NJBPU-approved NUG deferred cost recovery, which was the primary cause for the decrease in the first six months of 2011 principally from lower storm restoration costs. The amortization of regulatory assets, decreased by $29 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011, partially offset by lower storm cost deferrals and the write-off of nonrecoverable NUG costs.net.
141
METROPOLITAN EDISON COMPANY
MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed 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.
As authorized by Met-Ed’s Board of Directors, Met-Ed returned $150 million of capital to FirstEnergy Corp. on May 31, 2011, the sole owner of all of the shares of Met-Ed’s common stock.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $10 million in the first six 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 by $279 million, or 30%, in the first six months of 2011 compared to the same period of 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.
Distribution revenues decreased by $154 million in the first six 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. Slightly higher KWH deliveries reflect increased weather-related usage due to an 8% increase in heating degree days offsetting a 15% decrease in cooling degree days in the first six months of 2011, compared to the same period in 2010.
Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | 0.2 | % |
Commercial | | | (4.1 | )% |
Industrial | | | 3.6 | % |
| | | |
Net Increase in Distribution Deliveries
| | | 0.5 | % |
| | | |
| | | | | |
| Distribution Revenues | | Decrease | |
| | | (In millions) | |
| Residential | | $ | (58 | ) |
| Commercial | | | (47 | ) |
| Industrial | | | (49 | ) |
| | | | |
Decrease in Distribution Revenues | | $ | (154 | ) |
| | | | |
Retail generation revenues decreased by $10 million in the first six months of 2011 compared to the same period of 2010, due to lower KWH sales to all customer classes resulting from increased customer shopping. Customer shopping has increased for residential, commercial and industrial classes by 1%, 42% and 87%, respectively. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.
142
Changes in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
Retail Generation KWH Sales | | Decrease | |
| | | | |
Residential | | | (1.0 | )% |
Commercial | | | (44.7 | )% |
Industrial | | | (87.6 | )% |
| | | |
Decrease in Retail Generation Sales
| | | (43.1 | )% |
| | | |
| | | | | |
| | | Increase | |
| Retail Generation Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 88 | |
| Commercial | | | (14 | ) |
| Industrial | | | (84 | ) |
| | | | |
Net Decrease in Retail Generation Revenues | | $ | (10 | ) |
| | | | |
Wholesale revenues decreased by $105 million in the first six 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 by $11 million in the first six months of 2011 compared to the same period of 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. 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 $290 million in the first six 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 | | $ | (149 | ) |
Other operating costs | | | (95 | ) |
Provision for depreciation | | | (1 | ) |
Amortization of regulatory assets, net | | | (43 | ) |
General taxes | | | (2 | ) |
| | | |
Decrease in Expenses
| | $ | (290 | ) |
| | | |
Purchased power costs decreased by $149 million in the first six 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 $95 million in the first six months of 2011 compared to the same period in 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above) partially offset by increased costs for energy efficiency programs. The amortization of regulatory assets decreased $43 million in the first six months of 2011 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $2 million in the first six months of 2011 primarily due to lower gross receipts taxes.
Other Expense
In the first six months of 2011, interest income decreased by $2 million due to reduced CTC stranded asset balances compared to the same period of 2010.
143
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 electric transmission and distribution services. Penelec also procures generation service for those customers electing to retain Penelec as their power supplier. 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: Regulatory Assets, Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.
Results of Operations
Net income increased by $2 million in the first six 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 and higher net amortization of regulatory assets.
Revenues
Revenues decreased by $193 million, or 25%, in the first six months of 2011 compared to the same period of 2010. The decrease in revenue was primarily due to lower distribution revenues, retail and wholesale generation revenues, and transmission revenues.
Distribution revenues decreased by $5 million in the first six 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, partially offset by a PPUC approved rate adjustment for NUG costs. Higher KWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territories, compared to the first six months of 2010. Lower KWH deliveries to residential and commercial customers in the first six months of 2011 reflected lower weather-related usage as cooling degree days were 10% below the same period in 2010.
Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
| | Increase | |
Distribution KWH Deliveries | | (Decrease) | |
| | | | |
Residential | | | (1.2 | )% |
Commercial | | | (4.7 | )% |
Industrial | | | 7.3 | % |
| | | |
Net Increase in Distribution Deliveries
| | | 1.4 | % |
| | | |
| | | | | |
| | | Increase | |
| Distribution Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 3 | |
| Commercial | | | (14 | ) |
| Industrial | | | 6 | |
| | | | |
Net Decrease in Distribution Revenues | | $ | (5 | ) |
| | | | |
Retail generation revenues decreased by $80 million in the first six months of 2011, compared to the same period of 2010, due to lower KWH sales for all customer classes resulting from increased customer shopping. The increase in customer shopping for residential, commercial and industrial customer classes was 2%, 45% and 81%, respectively. The impact of customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.
144
Changes in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:
| | | | |
Retail Generation KWH Sales | | Decrease | |
| | | | |
Residential | | | (2.7 | )% |
Commercial | | | (47.1 | )% |
Industrial | | | (87.4 | )% |
| | | |
Decrease in Retail Generation Sales
| | | (47.5 | )% |
| | | |
| | | | | |
| | | Increase | |
| Retail Generation Revenues | | (Decrease) | |
| | | (In millions) | |
| Residential | | $ | 52 | |
| Commercial | | | (35 | ) |
| Industrial | | | (97 | ) |
| | | | |
Net Decrease in Retail Generation Revenues | | $ | (80 | ) |
| | | | |
Wholesale generation revenues decreased by $98 million in the first six months of 2011, compared to the same period of 2010, due to Penelec no longer purchasing non-NUG capacity for resale to the PJM market beginning in 2011.
Transmission revenues decreased by $11 million in the first six months of 2011, compared to the same period of 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Expenses
Total expenses decreased by $200 million in the first six months of 2011, as compared with the same period of 2010. The following table presents changes from the prior year by expense category:
| | | | | |
| | | Increase | |
| Expenses - Changes | | (Decrease) | |
| | | (In millions) | |
| Purchased power costs | | $ | (192 | ) |
| Other operating costs | | | (53 | ) |
| Amortization of regulatory assets, net | | | 46 | |
| Provision for depreciation | | | (1 | ) |
| | | | |
Net Decrease in Expenses | | $ | (200 | ) |
| | | | |
Purchased power costs decreased by $192 million in the first six months of 2011, compared to the same period of 2010, due to decreased KWH purchased to source generation sales requirements. Other operating costs decreased by $53 million in the first six months of 2011, due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). The amortization of net regulatory assets increased by $46 million in the first six months of 2011, primarily due to reduced NUG deferrals as a result of a PPUC approved increase in Penelec’s NUG cost recovery rider in January 2011.
145
| | |
ITEM 3. | | ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK |
See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
| | |
ITEM 4. | | CONTROLS AND PROCEDURES
|
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
The management of each registrant, with the participation of each registrant’s chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of the registrant’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)15d-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 of each registrant have concluded that each respective registrant’s disclosure controls and procedures were effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING
During the quarter ended June 30, 2011,2012, other than the changes resulting from the Allegheny mergersystem integration discussed below, there have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s, FES’, OE’s CEI’s, TE’s,and JCP&L’s Met-Ed’s and Penelec’s internal control over financial reporting.
On February 25, 2011,In April 2012, FirstEnergy integrated Allegheny into its IT business networks and financial systems following completion of the merger between FirstEnergy and Allegheny closed. FirstEnergy is currently in 2011. This initiative completes the processintegration of integrating Allegheny’sAllegheny's financial 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.controls into FirstEnergy.
146
PART II. OTHER INFORMATION
| | |
ITEM 1. | | ITEM 1. LEGAL PROCEEDINGS |
Information required for Part II, Item 1 is incorporated by reference to the discussions in NotesNote 8, Regulatory Matters, and Note 9, Commitments, Guarantees and 10Contingencies, of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.
ITEM 1A. RISK FACTORS
For the quarter ended June 30, 2011,2012, there have been no material changes to the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2010, as modified by changes to certain risk factors disclosed in our Quarterly Report on Form 10-Q for the period ended March 31, 2011.2011.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
| | |
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 second quarter of 2011.2012.
| | | | | | | | | | | | | | | | | |
| | | Period | |
| | | April | | | May | | | June | | | Second Quarter | |
| | | | | | | | | | | | | | | | | |
Total Number of Shares Purchased(a) | | | 213,550 | | | | 367,422 | | | | 428,966 | | | | 1,009,938 | |
| | | | | | | | | | | | | | | | | |
Average Price Paid per Share | | $ | 38.59 | | | $ | 42.62 | | | $ | 44.44 | | | $ | 42.54 | |
| | | | | | | | | | | | | | | | | |
| 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 |
| | April | | May | | June | | Second Quarter |
| | | | | | | | |
Total Number of Shares Purchased(1) | 60,533 |
| | 416,736 |
| | 454,399 |
| | 931,668 |
|
| Average Price Paid per Share | $ | 45.99 |
| | $ | 47.37 |
| | $ | 47.09 |
| | $ | 47.15 |
|
| Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs | — |
| | — |
| | — |
| | — |
|
| Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs | — |
| | — |
| | — |
| | — |
|
| | |
(a) | (1) | 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,DCPD, EDCP, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan,LTIP, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan,LTIP, Allegheny Energy, Inc,Inc., Non-Employee Director Stock Plan, Allegheny Energy, Inc,Inc., Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan. |
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
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.
147
Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended June 30, 2011:
| | | | | |
| | | Signal | |
| | | Peak | |
| Number of significant and substantial violations of mandatory health or safety standards under 104* | | | 30 | |
| 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) | | | 8 | |
| Number of mining related fatalities | | | — | |
| Total dollar value of proposed assessments | | $ | 6,989 | |
| | |
* | | 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.
| | | | |
| Exhibit Number | | |
| | | | |
| FirstEnergy | | |
| 3.1 | | | Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 21011) |
| | | | |
| | 10.1 | | U.S. $1,000,000,000 Credit Agreement, dated as of May 8, 2012, among FirstEnergy Transmission, LLC, American Transmission Systems, Incorporated and Trans-Allegheny Interstate Line Company, as borrowers, PNC Bank, National Association, as administrative agent, and the lending banks and fronting banks identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.1, File No. 333-21011). |
| | 10.2 | | Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011). |
| (A) | 10.3 | | | | Form of Officer Indemnification Agreement (incorporated by reference to FirstEnergy's Form 8-K filed July 23, 2012, Exhibit 10.1, File No. 333-21011). |
| (B) | 12 | | | Fixed charge ratiosratio |
| | | | |
| (B) | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | |
| 101 | * |
| The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2011,2012, formatted in XBRL (extensible(Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of 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. |
148
| | | | |
Exhibit Number | FES | |
FES | | |
| (B) | 10.1 | | First Supplemental Trust Indenture, dated April 2, 2012, supplementing and amending that certain Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Mellon Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (FirstEnergy Generation Corp. Project), which trust indenture, as amended, is substantially similar to various other PCRB trust indentures of FirstEnergy Generation Corp. |
| (B) | 10.2 | | First Amendment to Loan Agreement dated April 2, 2012, amending the Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006, which loan agreement, as amended, is substantially similar to various other PCRB loan agreements of FirstEnergy Generation Corp. |
| (B) | 10.3 | | First Supplemental Trust Indenture, dated April 2, 2012, supplementing and amending that certain Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Mellon Trust Company, N.A., as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project), which trust indenture, as amended, is substantially similar to various other PCRB trust indentures of FirstEnergy Nuclear Generation Corp. |
| (B) | 10.4 | | First Amendment to Loan Agreement dated April 2, 2012, amending the Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006, which loan agreement, as amended, is substantially similar to various other PCRB loan agreements of FirstEnergy Nuclear Generation Corp. |
| 10.5 | | Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp., and Allegheny Energy Supply Company, LLC, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.3, File No. 333-21011). |
| | | | |
| 12 | | | Fixed charge ratios |
| | | | |
| (B) | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | |
| 101 | * | | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended June 30, 2011,2012, 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. |
| | | | | |
| OE | | |
| | 10.1 | | | Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011). |
| | | | |
| 12 | | | Fixed charge ratios |
| | | | |
| (B) | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
|
| | | | |
| | 101 | * | | The following materials from the Quarterly Report on Form 10-Q of Ohio Edison Company. for the period ended June 30, 2011,2012, 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. |
| | | | | |
CEI | JCP&L | |
| | 10.1 | | | Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011). |
| | | | |
| 12 | | | Fixed charge ratios |
| | | | |
| (B) | 31.1 | | | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 31.2 | | | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) |
| | | | |
| (B) | 32 | | | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
| | | | | |
| 101 | * | | The following materials from the Quarterly Report on Form 10-Q of The Cleveland Electric IlluminatingJersey Central Power & Light Company. for the period ended June 30, 2011,2012, 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. |
149
| | | | |
Exhibit Number | | |
TE | | |
| 10.1 | | | Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. |
| | | | |
| 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 | * | | The following materials from the Quarterly Report on Form 10-Q of The Toledo Edison Company. for the period ended June 30, 2011, formatted in XBRL (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. |
| | | | | |
JCP&L | | |
| 10.1(A) | | | Credit Agreement, dated asManagement contract or compensatory plan, contract or agreement filed pursuant to Item 601 of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.Regulation S-K. |
| (B) | | | | |
| 12 | | | Fixed charge ratios |
| | | | |
| 31.1 | | | Certification of chief executive officer,Provided herein in electronic format 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 | * | | The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company. for the period ended June 30, 2011, formatted in XBRL (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. |
| | | | |
Met-Ed | | |
| 10.1 | | | Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. |
| | | | |
| 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 1350an exhibit. |
150
| | | | |
Exhibit Number | | |
| 101 | * | | The following materials from the Quarterly Report on Form 10-Q of Metropolitan Edison Company. for the period ended June 30, 2011, formatted in XBRL (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. |
| | | | |
Penelec | | |
| 10.1 | | | Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein. |
| | | | |
| 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 | * | | The following materials from the Quarterly Report on Form 10-Q of Pennsylvania Electric Company. for the period ended June 30, 2011, formatted in XBRL (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. |
| | |
| * | | 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 thesethis data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange CommissionSEC that this Interactive Data File isFiles of FES, OE and JCP&L are 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, isare 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,nor 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.
151
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.
August 2, 20117, 2012
|
| |
| | FIRSTENERGY CORP. |
| | Registrant |
| | |
| | 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
|
| | |
| | OHIO EDISON COMPANY |
| | Registrant |
| |
| /s/ Harvey L. Wagner |
| | Harvey L. Wagner | |
| | Vice President, Controller
and Chief Accounting Officer | |
|
| JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
| |
| | |
| | K. Jon TaylorJERSEY CENTRAL POWER & LIGHT COMPANY |
| Registrant |
| | |
| | /s/ Marlene A. Barwood |
| Marlene A. Barwood |
| Controller
(Principal Accounting Officer) | |
152