Combined Notes To Consolidated Financial Statements26-65 | | | Report of Independent Registered Public Accounting Firm | | | | FirstEnergy Corp. | 66 | FirstEnergy Solutions Corp. | 67 | Ohio Edison Company | 68 | The Cleveland Electric Illuminating Company | 69 | The Toledo Edison Company | 70 | Jersey Central Power & Light Company | Pages | | | | | Management's Narrative Analysis of Results of Operations | 66-67 | | Report of Independent Registered Public Accounting Firm | 68 | | Consolidated Statements of Income and Comprehensive Income | 69 | | Consolidated Balance Sheets | 70 | | Consolidated Statements of Cash Flows | 71 | | | | Metropolitan Edison Company | | | | | | Management's Narrative Analysis of Results of Operations | 72-73 | | Report of Independent Registered Public Accounting Firm | 74 | | Consolidated Statements of Income and Comprehensive Income | 75 | | Consolidated Balance Sheets | 76 | | Consolidated Statements of Cash Flows | 77 | | | 72 | Pennsylvania Electric Company | 73 | | | | | Item 2. Management's Narrative Analysis of Results of Operations | 78-79 | | Report of Independent Registered Public Accounting Firm | 80 | | Consolidated Statements of Income and Comprehensive Income | 81 | | Consolidated Balance Sheets | 82 | | Consolidated Statements of Cash Flows | 83 | | | | Combined Management’s Discussion and Analysis of Registrant and Subsidiaries
| 84-9774-118 | | | Combined Notes to Consolidated Financial StatementsManagement's Narrative Analysis of Results of Operations
| 98-127 | | | FirstEnergy Solutions Corp. | 119-121 | Ohio Edison Company | 122-123 | The Cleveland Electric Illuminating Company | 124-125 | The Toledo Edison Company | 126-127 | Jersey Central Power & Light Company | 128-129 | Metropolitan Edison Company | 130-131 | Pennsylvania Electric Company | 132-133 | | | Item 3. Quantitative and Qualitative Disclosures About Market Risk.Risk | 128134 | | | | Item 4. Controls and Procedures – FirstEnergy.FirstEnergy | 128134 | | | Item 4T. Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec.Penelec | 128134 | | | | Part II. Other Information | | | | | Item 1. Legal Proceedings.Proceedings | 129135 | | | | Item 1A. Risk Factors.Factors | 129135 | | | Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.Proceeds | 129135 | | | Item 5. Other Information | 135 | | | Item 6. Exhibits.Exhibits | 130-131136-137 |
GLOSSARY OF TERMS
The following abbreviations and acronyms are used in this report to identify FirstEnergy Corp. and ourits current and former subsidiaries:
ATSI | American Transmission Systems, Inc.,Incorporated, owns and operates transmission facilities | CEI | The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary | FENOC | FirstEnergy Nuclear Operating Company, operates nuclear generating facilities | FES | FirstEnergy Solutions Corp., provides energy-related products and services | FESC | FirstEnergy Service Company, provides legal, financial and other corporate support services | FEV | FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures | FGCO | FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities | FirstEnergy | FirstEnergy Corp., a public utility holding company | GPU | GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001 | JCP&L | Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary | JCP&L Transition Funding | JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds | JCP&L Transition Funding II | JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds | Met-Ed | Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary | NGC | FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities | OE | Ohio Edison Company, an Ohio electric utility operating subsidiary | Ohio Companies | CEI, OE and TE | Penelec | Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary | Penn | Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE | Pennsylvania Companies | Met-Ed, Penelec and Penn | PNBV | PNBV Capital Trust, a special purpose entity created by OE in 1996 | Shelf Registrants | OE, CEI, TE, JCP&L, Met-Ed and Penelec | Shippingport | Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997 | Signal Peak | A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and coal transportation operations near Roundup, Montana | TE | The Toledo Edison Company, an Ohio electric utility operating subsidiary | Utilities | OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec | Waverly | The Waverly Power and Light Company, a wholly owned subsidiary of Penelec | | | The following abbreviations and acronyms are used to identify frequently used terms in this report: | | | AEP | American Electric Power Company, Inc. | ALJ | Administrative Law Judge | AMP-Ohio | American Municipal Power-Ohio, Inc. | AOCL | Accumulated Other Comprehensive Loss | AQC | Air Quality Control | BGS | Basic Generation Service | CAA | Clean Air Act | CAIR | Clean Air Interstate Rule | CAMR | Clean Air Mercury Rule | CBP | Competitive Bid Process | CO2 | Carbon Dioxide | CTC | Competitive Transition Charge | DOJ | United States Department of Justice | DPA | Department of the Public Advocate, Division of Rate Counsel (New Jersey) | EITFEE&C | Emerging Issues Task ForceEnergy Efficiency and Conservation | EMP | Energy Master Plan | EPA | United States Environmental Protection Agency | EPACT | Energy Policy Act of 2005 | ESP | Electric Security Plan | FASB | Financial Accounting Standards Board | FERC | Federal Energy Regulatory Commission | FINFMB | FASB InterpretationFirst Mortgage Bond | FIN 46RGAAP | FIN 46 (revised December 2003), "Consolidation of Variable Interest Entities"Accounting Principles Generally Accepted in the United States | FIN 48GHG | FIN 48, “Accounting for Uncertainty in Income Taxes-an interpretation of FASB Statement No. 109”Greenhouse Gases |
GLOSSARY OF TERMS, Cont’d.Cont'd.
FMB | First Mortgage Bond | FSP | FASB Staff Position | FSP FAS 107-1 and
APB 28-1
| FSP FAS 107-1 and APB 28-1, “Interim Disclosures about Fair Value of Financial Instruments” | FSP FAS 115-1
and SFAS 124-1
| FSP FAS 115-1 and SFAS 124-1, “The Meaning of Other-Than-Temporary Impairment and its
Application to Certain Investments”
| FSP FAS 115-2 and
FAS 124-2
| FSP FAS 115-2 and FAS 124-2, “Recognition and Presentation of Other-Than-Temporary
Impairments”
| FSP FAS 132(R)-1 | FSP FAS 132(R)-1, “Employers’ Disclosures about Postretirement Benefit Plan Assets” | FSP FAS 157-4 | FSP FAS 157-4, “Determining Fair Value When the Volume and Level of Activity for the Asset or
Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
| FTR | Financial Transmission Rights | GAAP | Accounting Principles Generally Accepted in the United States | GHG | Greenhouse Gases | ICE | Intercontinental Exchange | IRS | Internal Revenue Service | kV | Kilovolt | KWH | Kilowatt-hours | LED | Light-emitting Diode | LIBOR | London Interbank Offered Rate | LOC | Letter of Credit | MEIUG | Met-Ed Industrial Users Group | MISO | Midwest Independent Transmission System Operator, Inc. | Moody’sMoody's | Moody’sMoody's Investors Service, Inc. | MRO | Market Rate Offer | MW | Megawatts | MWH | Megawatt-hours | NAAQS | National Ambient Air Quality Standards | NERC | North American Electric Reliability Corporation | NJBPU | New Jersey Board of Public Utilities | NOV | Notice of Violation | NOX | Nitrogen Oxide | NRC | Nuclear Regulatory Commission | NSR | New Source Review | NUG | Non-Utility Generation | NUGC | Non-Utility Generation Charge | NYMEX | New York Mercantile Exchange | OCI | Other Comprehensive Income | OPEB | Other Post-Employment Benefits | OVEC | Ohio Valley Electric Corporation | PCRB | Pollution Control Revenue Bond | PICA | Penelec Industrial Customer Alliance | PJM | PJM Interconnection L. L. C. | PLR | Provider of Last Resort; an electric utility’sutility's obligation to provide generation service to customers whose alternative supplier fails to deliver service | PPUC | Pennsylvania Public Utility Commission | PSA | Power Supply Agreement | PUCO | Public Utilities Commission of Ohio | PUHCAQSPE | Public Utility Holding Company Act of 1935Qualifying Special-Purpose Entity | RCP | Rate Certainty Plan | RECB | Regional Expansion Criteria and Benefits | RFP | Request for Proposal | RSP | Rate Stabilization Plan | RTC | Regulatory Transition Charge | RTO | Regional Transmission Organization | S&P | Standard & Poor’sPoor's Ratings Service | SB221 | Amended Substitute Senate Bill 221 | SBC | Societal Benefits Charge | SEC | U.S. Securities and Exchange Commission | SECA | Seams Elimination Cost Adjustment | SFAS | Statement of Financial Accounting Standards |
GLOSSARY OF TERMS Cont’d.
SFAS 115 | SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities" | SFAS 133 | SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” | SFAS 157 | SFAS No. 157, “Fair Value Measurements” | SFAS 160 | SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – an Amendment
of ARB No. 51”
| SIP | State Implementation Plan(s) Under the Clean Air Act | SNCR | Selective Non-Catalytic Reduction | SO2 | Sulfur Dioxide | TBC | Transition Bond Charge | TMI-1 | Three Mile Island Unit 1 | TMI-2 | Three Mile Island Unit 2 | TSC | Transmission Service Charge | VERO | Voluntary Enhanced Retirement Option | VIE | Variable Interest Entity |
PART I. FINANCIAL INFORMATION
ITEMS 1. AND 2. FINANCIAL STATEMENTS AND MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
FIRSTENERGY CORP.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EXECUTIVE SUMMARY
Net income in the first quarter of 2009 was $115 million, or basic and diluted earnings of $0.39 per share of common stock, compared with net income of $277 million, or basic earnings of $0.91 per share of common stock ($0.90 diluted) in the first quarter of 2008. The decrease in FirstEnergy’s earnings resulted principally from regulatory charges ($168 million after-tax) recognized in the first quarter of 2009 primarily related to the implementation of the Ohio Companies’ Amended ESP.
Change in Basic Earnings Per Share
From Prior Year First Quarter
| | | | Basic Earnings Per Share – First Quarter 2008 | $ 0.91 | Regulatory charges – 2009 | (0.55) | Income tax resolution – 2009 | 0.04 | Organizational restructuring – 2009 | (0.05) | Gain on non-core asset sales – 2008 | (0.06) | Trust securities impairment | (0.04) | Revenues | 0.18 | Fuel and purchased power | (0.24) | Amortization / deferral of regulatory assets | 0.13 | Other expenses | 0.07 | Basic Earnings Per Share – First Quarter 2009 | $ 0.39 |
FIRSTENERGY CORP. | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In millions, except per share amounts) | | REVENUES: | | | | | | | | | | | | | Electric utilities | | $ | 2,940 | | | $ | 3,469 | | | $ | 8,751 | | | $ | 9,247 | | Unregulated businesses | | | 468 | | | | 435 | | | | 1,262 | | | | 1,179 | | Total revenues * | | | 3,408 | | | | 3,904 | | | | 10,013 | | | | 10,426 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Fuel | | | 302 | | | | 356 | | | | 890 | | | | 1,000 | | Purchased power | | | 1,313 | | | | 1,306 | | | | 3,480 | | | | 3,376 | | Other operating expenses | | | 665 | | | | 794 | | | | 2,103 | | | | 2,374 | | Provision for depreciation | | | 188 | | | | 168 | | | | 550 | | | | 500 | | Amortization of regulatory assets | | | 261 | | | | 291 | | | | 903 | | | | 795 | | Deferral of regulatory assets | | | - | | | | (58 | ) | | | (136 | ) | | | (261 | ) | General taxes | | | 192 | | | | 201 | | | | 587 | | | | 596 | | Total expenses | | | 2,921 | | | | 3,058 | | | | 8,377 | | | | 8,380 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 487 | | | | 846 | | | | 1,636 | | | | 2,046 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Investment income | | | 191 | | | | 40 | | | | 207 | | | | 73 | | Interest expense | | | (355 | ) | | | (192 | ) | | | (755 | ) | | | (559 | ) | Capitalized interest | | | 35 | | | | 15 | | | | 96 | | | | 36 | | Total other expense | | | (129 | ) | | | (137 | ) | | | (452 | ) | | | (450 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 358 | | | | 709 | | | | 1,184 | | | | 1,596 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 128 | | | | 238 | | | | 430 | | | | 585 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 230 | | | | 471 | | | | 754 | | | | 1,011 | | | | | | | | | | | | | | | | | | | Noncontrolling interest income (loss) | | | (4 | ) | | | - | | | | (14 | ) | | | 1 | | | | | | | | | | | | | | | | | | | EARNINGS AVAILABLE TO FIRSTENERGY CORP. | | $ | 234 | | | $ | 471 | | | $ | 768 | | | $ | 1,010 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.77 | | | $ | 1.55 | | | $ | 2.52 | | | $ | 3.32 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | | 304 | | | | 304 | | | | 304 | | | | 304 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK | | $ | 0.77 | | | $ | 1.54 | | | $ | 2.51 | | | $ | 3.29 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | | 306 | | | | 307 | | | | 306 | | | | 307 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | | $ | 1.10 | | | $ | 1.10 | | | $ | 1.65 | | | $ | 1.65 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | * Includes excise tax collections of $106 million and $115 million in the three months ended September 30, 2009 and 2008, respectively, | | and $310 million and $329 million in the nine months ended September 2009 and 2008, respectively. | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. | |
Regulatory Matters - Ohio
Ohio Regulatory Proceedings
On March 25, 2009, the PUCO issued an order approving the Ohio Companies’ Amended ESP, which includes provisions for establishing a competitive bid process for generation supply and pricing for a two-year period beginning June 1, 2009, freezing distribution rates through December 31, 2011, subject to limited exceptions, and reducing CEI’s recoverable Extended RTC balance as of May 31, 2009 by 50 percent ($216 million). On March 4, 2009, the PUCO issued an order allowing the Ohio Companies to provide electric generation service to their customers from April 1, 2009, through May 31, 2009, from FES at the average rate resulting from the Ohio Companies’ December 31, 2008, RFP. The PUCO also approved the continuation of CEI’s purchased power cost deferral and the process under which the Ohio Companies conducted their December RFP. The Amended ESP resulted from a stipulated agreement reached with the PUCO Staff and nearly all of the intervening parties to the case.
Regulatory Matters - Pennsylvania
Pennsylvania Legislative Process
The Governor of Pennsylvania signed Act 129 of 2008 into law in October 2008, which became effective November 14, 2008, to create an energy efficiency and conservation program with requirements to adopt and implement cost-effective plans to reduce energy consumption and peak demand. On March 26, 2009, the PPUC approved the company-specific energy consumption and peak demand reductions that must be achieved under Act 129, which requires electric distribution companies to reduce electricity consumption by 1% by May 31, 2011 and by 3% by May 31, 2013, and an annual system peak demand reduction of 4.5% by May 31, 2013. Costs associated with achieving the reduction will be recovered from customers. Under Act 129, electric distribution companies must develop and file their energy efficiency and peak load reduction plans for compliance with these requirements by July 1, 2009.
Act 129 also requires electric distribution companies to submit by August 14, 2009, a plan to deploy smart metering technology over a time period not to exceed fifteen years. The costs of developing and implementing the plan as ultimately approved by the PPUC will be recovered from customers.
Met-Ed and Penelec Transmission Rider Filings
On April 15, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increase to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to their TSC for the period June 1, 2008, through May 31, 2009. The PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC which included a transition approach that would recover past under-recovered costs of $144 million plus carrying charges over a 31-month period and deferral of a portion ($92 million) of projected costs for recovery over a 19-month period beginning June 1, 2009, through December 31, 2010. Hearings and briefing were concluded in February 2009. On March 4, 2009, MEIUG and PICA filed a Petition to reopen the record. Met-Ed and Penelec filed objections to MEIUG and PICA’s Petition on March 13, 2009, resulting in an April 1, 2009, order denying MEIUG & PICA’s Petition to reopen the record. Met-Ed is awaiting a final PPUC decision.
Met-Ed and Penelec Customer Prepayment Plan and Procurement Plan
On September 25, 2008, Met-Ed and Penelec filed a Voluntary Prepayment Plan with the PPUC that would provide an opportunity for residential and small commercial customers to prepay about 9.6% of their monthly electric bills during 2009 and 2010, which would earn interest at 7.5% and be used to reduce electricity charges in 2011 and 2012. Met-Ed, Penelec, the Office of Consumer Advocate and the Office of Small Business Advocate reached a settlement agreement on the Voluntary Prepayment Plan, which the PPUC approved on February 26, 2009.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011, through May 31, 2013. The plan is designed to provide adequate and reliable service through a prudent mix of long-term, short-term and spot market generation supply as required by Pennsylvania law. The plan proposes a staggered procurement schedule, which varies by customer class. On March 30, 2009, Met-Ed and Penelec filed written Direct Testimony; hearings are scheduled for July 15-17, 2009. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.
Met-Ed and Penelec NUG Statement Compliance Filing
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.
Regulatory Matters – New Jersey
JCP&L Solar Renewable Energy Proposal Approved
On March 27, 2009, the NJBPU approved JCP&L’s proposal to help increase the pace of solar energy project development in the state by establishing long-term agreements to purchase and sell Solar Renewable Energy Certificates, which will provide a stable basis for financing solar generation projects. The plan is expected to support the phase-in of approximately 42 megawatts of solar generating capacity over the next three years to help meet the state’s Renewable Portfolio Standards through 2012.FIRSTENERGY CORP. | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In millions) | | | | | | | | | | | | | | | NET INCOME | | $ | 230 | | | $ | 471 | | | $ | 754 | | | $ | 1,011 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (480 | ) | | | (20 | ) | | | 24 | | | | (60 | ) | Unrealized gain (loss) on derivative hedges | | | 19 | | | | 26 | | | | 57 | | | | 21 | | Change in unrealized gain on available-for-sale securities | | | (108 | ) | | | (100 | ) | | | (76 | ) | | | (181 | ) | Other comprehensive income (loss) | | | (569 | ) | | | (94 | ) | | | 5 | | | | (220 | ) | Income tax expense (benefit) related to other comprehensive income | | | (216 | ) | | | (34 | ) | | | 26 | | | | (81 | ) | Other comprehensive income (loss), net of tax | | | (353 | ) | | | (60 | ) | | | (21 | ) | | | (139 | ) | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) | | | (123 | ) | | | 411 | | | | 733 | | | | 872 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE | | | | | | | | | | | | | | | | | TO NONCONTROLLING INTEREST | | | (4 | ) | | | - | | | | (14 | ) | | | 1 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) AVAILABLE TO FIRSTENERGY CORP. | | $ | (119 | ) | | $ | 411 | | | $ | 747 | | | $ | 871 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of | | these statements. | | | | | | | | | | | | | | | | |
JCP&L Selected for Smart Grid Demonstration
JCP&L is one of three companies selected as a smart grid demonstration host site by the Electric Power Research Institute to test the integration of smart grid and other technologies into operations of existing systems. The technologies exhibited during this project may be one solution to accomplishing the goals of the New Jersey Energy Master Plan by meeting future electricity demand.
Operational Matters
Generation Outages
On February 23, 2009, the Perry Plant began its 12th scheduled refueling and maintenance outage, in which 280 of the plant’s 748 fuel assemblies will be exchanged, safety inspections will be conducted, and several maintenance projects will be completed, including replacement of the plant’s recirculation pump motor.
On April 20, 2009, Beaver Valley Unit 1 began a scheduled refueling and maintenance outage. During the outage, 62 of the 157 fuel assemblies will be exchanged and safety inspections will be conducted. Also, several projects will be completed to ensure continued safe and reliable operations, including maintenance on the cooling tower and the replacement of a pump motor. The unit operated safely and reliably for 545 consecutive days, beating the previous records of 456 days for Unit 1 and 537 days for Unit 2 set in 2006 and 2005, respectively.
FirstEnergy expects generation output for 2009 to be lower than 2008, partly related to three scheduled nuclear refueling outages in 2009 and a number of planned fossil outages in the second half of the year, including the tie in of Sammis Unit 6 as part of FirstEnergy’s air quality control project. FirstEnergy is also re-evaluating its near-term plans for maintenance and capital work and outages scheduled over the next several years and may take advantage of the reduced loads anticipated as a result of economic conditions to undertake additional work on its facilities, including its largest units.
R. E. Burger Plant
On April 1, 2009, FirstEnergy announced plans to retrofit Units 4 and 5 at its R.E. Burger Plant to repower the units with biomass. Retrofitting the Burger Plant will help meet the renewable energy goals set forth in Ohio SB221, utilize much of the existing infrastructure currently in place, preserve approximately 100 jobs and continue positive economic support to Belmont County, making the Burger Plant one of the largest biomass facilities in the United States.
OVEC Participation Interest Sale
On May 1, 2009, FGCO announced the sale of a 9% interest in the output from OVEC to Buckeye Power Generating LLC for $252 million. The sale involves the output of 214 MW from OVEC’s generating facilities in southern Indiana and Ohio. FGCO’s remaining interest in OVEC was reduced to 11.5%. This transaction is expected to increase earnings in the second quarter of 2009 by $159 million.
FirstEnergy Reorganization
On March 3, 2009, FirstEnergy announced it would reduce its management and support staff by 335 employees. This staffing reduction resulted from an effort to enhance efficiencies in response to the economic downturn. The reduction represents approximately four percent of FirstEnergy’s non-union workforce. Severance benefits and career counseling services were provided to eligible employees. Total one-time charges associated with the reorganization were approximately $22 million, or $0.05 per share of common stock.
Financial Matters
On January 20, 2009, Met-Ed issued $300 million of 7.70% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings. On January 27, 2009, JCP&L issued $300 million of 7.35% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings, repurchase equity from FirstEnergy, fund capital expenditures and for other general corporate purposes. On April 24, 2009, TE issued $300 million of 7.25% Senior Secured Notes due 2020 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes.
On February 12, 2009, $153 million of Wachovia LOCs supporting a like amount of NGC’s PCRBs were renewed until March 17, 2014, and on March 10, 2009, $100 million of FGCO’s PCRBs were converted from a variable-rate mode enhanced by Wachovia LOCs to a fixed-rate mode secured by FMBs.FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In millions) | | ASSETS | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 838 | | | $ | 545 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $28 million for uncollectible accounts) | | | 1,260 | | | | 1,304 | | Other (less accumulated provisions of $9 million for uncollectible accounts) | | | 132 | | | | 167 | | Materials and supplies, at average cost | | | 621 | | | | 605 | | Prepaid taxes | | | 585 | | | | 283 | | Other | | | 334 | | | | 149 | | | | | 3,770 | | | | 3,053 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | In service | | | 27,526 | | | | 26,482 | | Less - Accumulated provision for depreciation | | | 11,267 | | | | 10,821 | | | | | 16,259 | | | | 15,661 | | Construction work in progress | | | 2,490 | | | | 2,062 | | | | | 18,749 | | | | 17,723 | | INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 1,856 | | | | 1,708 | | Investments in lease obligation bonds | | | 553 | | | | 598 | | Other | | | 698 | | | | 711 | | | | | 3,107 | | | | 3,017 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 5,575 | | | | 5,575 | | Regulatory assets | | | 2,543 | | | | 3,140 | | Power purchase contract asset | | | 220 | | | | 434 | | Other | | | 710 | | | | 579 | | | | | 9,048 | | | | 9,728 | | | | $ | 34,674 | | | $ | 33,521 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 2,020 | | | $ | 2,476 | | Short-term borrowings | | | 1,653 | | | | 2,397 | | Accounts payable | | | 692 | | | | 794 | | Accrued taxes | | | 257 | | | | 333 | | Other | | | 1,114 | | | | 1,098 | | | | | 5,736 | | | | 7,098 | | CAPITALIZATION: | | | | | | | | | Common stockholders’ equity- | | | | | | | | | Common stock, $0.10 par value, authorized 375,000,000 shares- | | | 31 | | | | 31 | | 304,835,407 shares outstanding | | | | | | | | | Other paid-in capital | | | 5,438 | | | | 5,473 | | Accumulated other comprehensive loss | | | (1,401 | ) | | | (1,380 | ) | Retained earnings | | | 4,424 | | | | 4,159 | | Total common stockholders' equity | | | 8,492 | | | | 8,283 | | Noncontrolling interest | | | 1 | | | | 32 | | Total equity | | | 8,493 | | | | 8,315 | | Long-term debt and other long-term obligations | | | 11,647 | | | | 9,100 | | | | | 20,140 | | | | 17,415 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 2,562 | | | | 2,163 | | Asset retirement obligations | | | 1,401 | | | | 1,335 | | Deferred gain on sale and leaseback transaction | | | 1,001 | | | | 1,027 | | Power purchase contract liability | | | 685 | | | | 766 | | Retirement benefits | | | 1,500 | | | | 1,884 | | Lease market valuation liability | | | 274 | | | | 308 | | Other | | | 1,375 | | | | 1,525 | | | | | 8,798 | | | | 9,008 | | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 34,674 | | | $ | 33,521 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. | | | | | |
FIRSTENERGY CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In millions) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 754 | | | $ | 1,011 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 550 | | | | 500 | | Amortization of regulatory assets | | | 903 | | | | 795 | | Deferral of regulatory assets | | | (136 | ) | | | (261 | ) | Nuclear fuel and lease amortization | | | 92 | | | | 82 | | Deferred purchased power and other costs | | | (235 | ) | | | (138 | ) | Deferred income taxes and investment tax credits, net | | | 421 | | | | 278 | | Investment impairment | | | 39 | | | | 63 | | Deferred rents and lease market valuation liability | | | (20 | ) | | | (62 | ) | Accrued compensation and retirement benefits | | | 20 | | | | (127 | ) | Stock-based compensation | | | (1 | ) | | | (74 | ) | Gain on asset sales | | | (12 | ) | | | (43 | ) | Electric service prepayment programs | | | (10 | ) | | | (58 | ) | Cash collateral, net | | | (85 | ) | | | 21 | | Gain on investment securities held in trusts | | | (172 | ) | | | (43 | ) | Loss on debt redemption | | | 142 | | | | - | | Pension trust contribution | | | (500 | ) | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 78 | | | | (117 | ) | Materials and supplies | | | 30 | | | | (34 | ) | Prepaid taxes | | | (332 | ) | | | (259 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (103 | ) | | | (34 | ) | Accrued taxes | | | (97 | ) | | | (166 | ) | Accrued interest | | | 121 | | | | 107 | | Other | | | 17 | | | | (10 | ) | Net cash provided from operating activities | | | 1,464 | | | | 1,431 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 4,151 | | | | 631 | | Short-term borrowings, net | | | - | | | | 1,489 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (2,213 | ) | | | (733 | ) | Short-term borrowings, net | | | (764 | ) | | | - | | Net controlled disbursement activity | | | (15 | ) | | | 6 | | Common stock dividend payments | | | (503 | ) | | | (503 | ) | Other | | | (39 | ) | | | 21 | | Net cash provided from financing activities | | | 617 | | | | 911 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (1,575 | ) | | | (2,177 | ) | Proceeds from asset sales | | | 19 | | | | 64 | | Sales of investment securities held in trusts | | | 3,039 | | | | 1,144 | | Purchases of investment securities held in trusts | | | (3,101 | ) | | | (1,215 | ) | Cash investments | | | (4 | ) | | | 72 | | Restricted funds for debt redemption | | | (150 | ) | | | (82 | ) | Other | | | (16 | ) | | | (96 | ) | Net cash used for investing activities | | | (1,788 | ) | | | (2,290 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | 293 | | | | 52 | | Cash and cash equivalents at beginning of period | | | 545 | | | | 129 | | Cash and cash equivalents at end of period | | $ | 838 | | | $ | 181 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | | part of these statements. | | | | | | | | |
On March 31, 2009, FES and FGCO executed a new $100 million, two-year secured term loan facility with The Royal Bank of Scotland Finance (Ireland) (RBSFI) that replaces an existing $100 million borrowing facility with RBSFI that was expiring in November 2009.
FIRSTENERGY’S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).
· | Energy Delivery Services transmits and distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements in Pennsylvania and New Jersey. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy’s service areas and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service) in its Pennsylvania and New Jersey franchise areas.
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· | Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the PLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan and Illinois. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is primarily derived from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment’s customers.
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· | Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of FirstEnergy’s Ohio Companies. The segment's net income is primarily derived from electric generation sales revenues less the cost of power purchased through the Ohio Companies’ CBP, including net transmission and ancillary costs charged by MISO to deliver energy to retail customers.
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RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 11 to the consolidated financial statements. Net income by major business segment was as follows:
| | Three Months Ended | | | | | | March 31 | | Increase | | | | 2009 | | 2008 | | (Decrease) | | Earnings (Loss) | | (In millions, except per share data) | | By Business Segment | | | | | | | | | | | | ) | | | | | | ) | Competitive energy services | | | | | | | | | | | Ohio transitional generation services | | | | | | | | | | | Other and reconciling adjustments* | | | | ) | | | ) | | | ) | | | | | | | | | | | ) | | | | | | | | | | | | | | $ | 0.39 | | $ | 0.91 | | $ | (0.52 | ) | Diluted Earnings Per Share | | $ | 0.39 | | $ | 0.90 | | $ | (0.51 | ) |
* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and elimination of intersegment transactions.
Summary of Results of Operations – First Quarter 2009 Compared with First Quarter 2008
Financial results for FirstEnergy's major business segments in the first three months of 2009 and 2008 were as follows:
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | First Quarter 2009 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 1,959 | | | $ | 280 | | | $ | 902 | | | $ | - | | | $ | 3,141 | | Other | | | 150 | | | | 55 | | | | 10 | | | | (22 | ) | | | 193 | | Internal | | | - | | | | 893 | | | | - | | | | (893 | ) | | | - | | Total Revenues | | | 2,109 | | | | 1,228 | | | | 912 | | | | (915 | ) | | | 3,334 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | - | | | | 312 | | | | - | | | | - | | | | 312 | | Purchased power | | | 978 | | | | 160 | | | | 898 | | | | (893 | ) | | | 1,143 | | Other operating expenses | | | 480 | | | | 355 | | | | 18 | | | | (26 | ) | | | 827 | | Provision for depreciation | | | 109 | | | | 64 | | | | - | | | | 4 | | | | 177 | | Amortization of regulatory assets | | | 406 | | | | - | | | | 5 | | | | - | | | | 411 | | Deferral of new regulatory assets | | | (43 | ) | | | - | | | | (50 | ) | | | - | | | | (93 | ) | General taxes | | | 168 | | | | 32 | | | | 2 | | | | 9 | | | | 211 | | Total Expenses | | | 2,098 | | | | 923 | | | | 873 | | | | (906 | ) | | | 2,988 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 11 | | | | 305 | | | | 39 | | | | (9 | ) | | | 346 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income (loss) | | | 29 | | | | (29 | ) | | | 1 | | | | (12 | ) | | | (11 | ) | Interest expense | | | (111 | ) | | | (28 | ) | | | - | | | | (55 | ) | | | (194 | ) | Capitalized interest | | | 1 | | | | 10 | | | | - | | | | 17 | | | | 28 | | Total Other Expense | | | (81 | ) | | | (47 | ) | | | 1 | | | | (50 | ) | | | (177 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | (70 | ) | | | 258 | | | | 40 | | | | (59 | ) | | | 169 | | Income taxes | | | (28 | ) | | | 103 | | | | 16 | | | | (37 | ) | | | 54 | | Net Income (Loss) | | | (42 | ) | | | 155 | | | | 24 | | | | (22 | ) | | | 115 | | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | (4 | ) | | | (4 | ) | Earnings (Loss) Available To Parent | | $ | (42 | ) | | $ | 155 | | | $ | 24 | | | $ | (18 | ) | | $ | 119 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales to affiliates | | $ | 616,300 | | | $ | 785,681 | | | $ | 2,348,741 | | | $ | 2,266,271 | | Electric sales to non-affiliates | | | 443,819 | | | | 381,483 | | | | 928,944 | | | | 994,100 | | Other | | | 44,453 | | | | 74,440 | | | | 394,145 | | | | 151,627 | | Total revenues | | | 1,104,572 | | | | 1,241,604 | | | | 3,671,830 | | | | 3,411,998 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Fuel | | | 294,693 | | | | 349,946 | | | | 871,160 | | | | 982,185 | | Purchased power from non-affiliates | | | 205,200 | | | | 221,493 | | | | 551,155 | | | | 648,556 | | Purchased power from affiliates | | | 35,290 | | | | 15,821 | | | | 149,746 | | | | 75,834 | | Other operating expenses | | | 305,935 | | | | 279,184 | | | | 891,555 | | | | 863,468 | | Provision for depreciation | | | 66,041 | | | | 64,633 | | | | 192,962 | | | | 170,535 | | General taxes | | | 21,700 | | | | 21,736 | | | | 66,361 | | | | 64,728 | | Total expenses | | | 928,859 | | | | 952,813 | | | | 2,722,939 | | | | 2,805,306 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 175,713 | | | | 288,791 | | | | 948,891 | | | | 606,692 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Investment income (loss) | | | 158,857 | | | | 11,961 | | | | 135,723 | | | | (6,332 | ) | Miscellaneous income | | | 2,804 | | | | 6,466 | | | | 12,840 | | | | 19,781 | | Interest expense to affiliates | | | (2,209 | ) | | | (8,015 | ) | | | (8,503 | ) | | | (25,953 | ) | Interest expense - other | | | (42,187 | ) | | | (32,769 | ) | | | (90,985 | ) | | | (81,809 | ) | Capitalized interest | | | 17,869 | | | | 12,395 | | | | 41,975 | | | | 29,599 | | Total other income (expense) | | | 135,134 | | | | (9,962 | ) | | | 91,050 | | | | (64,714 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 310,847 | | | | 278,829 | | | | 1,039,941 | | | | 541,978 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 111,164 | | | | 93,174 | | | | 372,175 | | | | 198,245 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 199,683 | | | | 185,655 | | | | 667,766 | | | | 343,733 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (61,085 | ) | | | (1,821 | ) | | | 13,604 | | | | (5,462 | ) | Unrealized gain on derivative hedges | | | 790 | | | | 27,277 | | | | 26,847 | | | | 15,075 | | Change in unrealized gain on available-for-sale securities | | | (89,401 | ) | | | (90,198 | ) | | | (51,374 | ) | | | (159,759 | ) | Other comprehensive loss | | | (149,696 | ) | | | (64,742 | ) | | | (10,923 | ) | | | (150,146 | ) | Income tax benefit related to other comprehensive loss | | | (58,883 | ) | | | (24,781 | ) | | | (3,549 | ) | | | (55,497 | ) | Other comprehensive loss, net of tax | | | (90,813 | ) | | | (39,961 | ) | | | (7,374 | ) | | | (94,649 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 108,870 | | | $ | 145,694 | | | $ | 660,392 | | | $ | 249,084 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an integral part of | | these statements. | | | | | | | | | | | | | | | | |
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | First Quarter 2008 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 2,050 | | | $ | 289 | | | $ | 691 | | | $ | - | | | $ | 3,030 | | Other | | | 162 | | | | 40 | | | | 16 | | | | 29 | | | | 247 | | Internal | | | - | | | | 776 | | | | - | | | | (776 | ) | | | - | | Total Revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | (747 | ) | | | 3,277 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 1 | | | | 327 | | | | - | | | | - | | | | 328 | | Purchased power | | | 982 | | | | 206 | | | | 588 | | | | (776 | ) | | | 1,000 | | Other operating expenses | | | 445 | | | | 309 | | | | 77 | | | | (32 | ) | | | 799 | | Provision for depreciation | | | 106 | | | | 53 | | | | - | | | | 5 | | | | 164 | | Amortization of regulatory assets | | | 249 | | | | - | | | | 9 | | | | - | | | | 258 | | Deferral of new regulatory assets | | | (100 | ) | | | - | | | | (5 | ) | | | - | | | | (105 | ) | General taxes | | | 173 | | | | 32 | | | | 1 | | | | 9 | | | | 215 | | Total Expenses | | | 1,856 | | | | 927 | | | | 670 | | | | (794 | ) | | | 2,659 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 356 | | | | 178 | | | | 37 | | | | 47 | | | | 618 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 45 | | | | (6 | ) | | | 1 | | | | (23 | ) | | | 17 | | Interest expense | | | (103 | ) | | | (34 | ) | | | - | | | | (42 | ) | | | (179 | ) | Capitalized interest | | | - | | | | 7 | | | | - | | | | 1 | | | | 8 | | Total Other Expense | | | (58 | ) | | | (33 | ) | | | 1 | | | | (64 | ) | | | (154 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 298 | | | | 145 | | | | 38 | | | | (17 | ) | | | 464 | | Income taxes | | | 119 | | | | 58 | | | | 15 | | | | (5 | ) | | | 187 | | Net Income | | | 179 | | | | 87 | | | | 23 | | | | (12 | ) | | | 277 | | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | 1 | | | | 1 | | Earnings Available To Parent | | $ | 179 | | | $ | 87 | | | $ | 23 | | | $ | (13 | ) | | $ | 276 | | | | | | | | | | | | | | | | | | | | | | | Changes Between First Quarter 2009 and | | | | | | | | | | | | | | | | | | | | | First Quarter 2008 Financial Results | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | | | Electric | | $ | (91 | ) | | $ | (9 | ) | | $ | 211 | | | $ | - | | | $ | 111 | | Other | | | (12 | ) | | | 15 | | | | (6 | ) | | | (51 | ) | | | (54 | ) | Internal | | | - | | | | 117 | | | | - | | | | (117 | ) | | | - | | Total Revenues | | | (103 | ) | | | 123 | | | | 205 | | | | (168 | ) | | | 57 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | (1 | ) | | | (15 | ) | | | - | | | | - | | | | (16 | ) | Purchased power | | | (4 | ) | | | (46 | ) | | | 310 | | | | (117 | ) | | | 143 | | Other operating expenses | | | 35 | | | | 46 | | | | (59 | ) | | | 6 | | | | 28 | | Provision for depreciation | | | 3 | | | | 11 | | | | - | | | | (1 | ) | | | 13 | | Amortization of regulatory assets | | | 157 | | | | - | | | | (4 | ) | | | - | | | | 153 | | Deferral of new regulatory assets | | | 57 | | | | - | | | | (45 | ) | | | - | | | | 12 | | General taxes | | | (5 | ) | | | - | | | | 1 | | | | - | | | | (4 | ) | Total Expenses | | | 242 | | | | (4 | ) | | | 203 | | | | (112 | ) | | | 329 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | (345 | ) | | | 127 | | | | 2 | | | | (56 | ) | | | (272 | ) | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income (loss) | | | (16 | ) | | | (23 | ) | | | - | | | | 11 | | | | (28 | ) | Interest expense | | | (8 | ) | | | 6 | | | | - | | | | (13 | ) | | | (15 | ) | Capitalized interest | | | 1 | | | | 3 | | | | - | | | | 16 | | | | 20 | | Total Other Income (Expense) | | | (23 | ) | | | (14 | ) | | | - | | | | 14 | | | | (23 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | (368 | ) | | | 113 | | | | 2 | | | | (42 | ) | | | (295 | ) | Income taxes | | | (147 | ) | | | 45 | | | | 1 | | | | (32 | ) | | | (133 | ) | Net Income | | | (221 | ) | | | 68 | | | | 1 | | | | (10 | ) | | | (162 | ) | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | (5 | ) | | | (5 | ) | Earnings Available To Parent | | $ | (221 | ) | | $ | 68 | | | $ | 1 | | | $ | (5 | ) | | $ | (157 | ) |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 266,958 | | | $ | 39 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $4,676,000 and $5,899,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 155,489 | | | | 86,123 | | Associated companies | | | 344,387 | | | | 378,100 | | Other (less accumulated provisions of $6,702,000 and $6,815,000 | | | | | | | | | respectively, for uncollectible accounts) | | | 47,579 | | | | 24,626 | | Notes receivable from associated companies | | | 428,016 | | | | 129,175 | | Materials and supplies, at average cost | | | 528,278 | | | | 521,761 | | Prepayments and other | | | 120,362 | | | | 112,535 | | | | | 1,891,069 | | | | 1,252,359 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | In service | | | 10,254,698 | | | | 9,871,904 | | Less - Accumulated provision for depreciation | | | 4,487,832 | | | | 4,254,721 | | | | | 5,766,866 | | | | 5,617,183 | | Construction work in progress | | | 2,195,999 | | | | 1,747,435 | | | | | 7,962,865 | | | | 7,364,618 | | INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 1,101,884 | | | | 1,033,717 | | Long-term notes receivable from associated companies | | | 8,817 | | | | 62,900 | | Other | | | 26,642 | | | | 61,591 | | | | | 1,137,343 | | | | 1,158,208 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Accumulated deferred income tax benefits | | | 38,099 | | | | 267,762 | | Lease assignment receivable from associated companies | | | 71,356 | | | | 71,356 | | Goodwill | | | 24,248 | | | | 24,248 | | Property taxes | | | 50,104 | | | | 50,104 | | Unamortized sale and leaseback costs | | | 58,350 | | | | 69,932 | | Other | | | 226,134 | | | | 96,434 | | | | | 468,291 | | | | 579,836 | | | | $ | 11,459,568 | | | $ | 10,355,021 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 1,631,766 | | | $ | 2,024,898 | | Short-term borrowings- | | | | | | | | | Associated companies | | | - | | | | 264,823 | | Other | | | 100,000 | | | | 1,000,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 387,182 | | | | 472,338 | | Other | | | 156,053 | | | | 154,593 | | Accrued taxes | | | 105,574 | | | | 79,766 | | Other | | | 227,788 | | | | 248,439 | | | | | 2,608,363 | | | | 4,244,857 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity - | | | | | | | | | Common stock, without par value, authorized 750 shares, | | | | | | | | | 7 shares outstanding | | | 1,466,697 | | | | 1,464,229 | | Accumulated other comprehensive loss | | | (99,245 | ) | | | (91,871 | ) | Retained earnings | | | 2,239,831 | | | | 1,572,065 | | Total common stockholder's equity | | | 3,607,283 | | | | 2,944,423 | | Long-term debt and other long-term obligations | | | 2,640,092 | | | | 571,448 | | | | | 6,247,375 | | | | 3,515,871 | | NONCURRENT LIABILITIES: | | | | | | | | | Deferred gain on sale and leaseback transaction | | | 1,001,298 | | | | 1,026,584 | | Accumulated deferred investment tax credits | | | 59,479 | | | | 62,728 | | Asset retirement obligations | | | 906,199 | | | | 863,085 | | Retirement benefits | | | 200,097 | | | | 194,177 | | Property taxes | | | 50,104 | | | | 50,104 | | Lease market valuation liability | | | 273,624 | | | | 307,705 | | Other | | | 113,029 | | | | 89,910 | | | | | 2,603,830 | | | | 2,594,293 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 11,459,568 | | | $ | 10,355,021 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part | | of these statements. | | | | | | | | |
Energy Delivery Services – First Quarter 2009 Compared with First Quarter 2008
This segment recognized a net loss of $42 million in the first three months of 2009 compared to net income of $179 million in the first three months of 2008, primarily due to CEI’s $216 million regulatory asset impairment related to the implementation of the Ohio Companies’ Amended ESP and other regulatory charges.
Revenues –
The decrease in total revenues of $103 million resulted from the following sources:
| | Three Months Ended | | | | | | March 31 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) |
The change in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries | | | | | | | | | | | | | | | Total Distribution KWH Deliveries
| | | |
The lower revenues from distribution deliveries were driven by the reductions in sales volume. The decrease in electric distribution deliveries to commercial and industrial customers was primarily due to economic conditions in FirstEnergy’s service territory. In the industrial sector, KWH deliveries declined to major automotive (28.4%), steel (40.1%), and refinery customers (15.1%). Transition charges for OE and TE that ceased effective January 1, 2009, with the full recovery of related costs, were offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).
The following table summarizes the price and volume factors contributing to the $9 million decrease in generation revenues in the first quarter of 2009 compared to the first quarter of 2008:
Sources of Change in Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 3.5% decrease in sales volumes | | $ | (27 | ) | Change in prices | | | | | | | | | | Wholesale: | | | | | Effect of 11.6% decrease in sales volumes | | | (25 | ) | Change in prices | | | | ) | | | | | ) | Net Decrease in Generation Revenues | | | | ) |
The decrease in retail generation sales volumes was primarily due to weakened economic conditions partially offset by increased weather-related usage (heating degree days increased by 3.3% in the first quarter of 2009). The increase in retail generation prices during the first three months of 2009 reflected increased generation rates for JCP&L resulting from the New Jersey BGS auction and for Penn under its RFP process. Wholesale generation sales decreased principally as a result of JCP&L selling less power from NUGs. The decrease in prices reflected lower spot market prices for PJM market participants.
Transmission revenues increased $11 million primarily due to higher transmission rates for Met-Ed and Penelec resulting from the annual update to their TSC riders in mid-2008. Met-Ed and Penelec defer the difference between revenues from their transmission rider and transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 667,766 | | | $ | 343,733 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 192,962 | | | | 170,535 | | Nuclear fuel and lease amortization | | | 94,244 | | | | 81,950 | | Deferred rents and lease market valuation liability | | | (40,143 | ) | | | (36,702 | ) | Deferred income taxes and investment tax credits, net | | | 268,812 | | | | 91,082 | | Investment impairment | | | 36,169 | | | | 58,173 | | Accrued compensation and retirement benefits | | | 5,860 | | | | (2,110 | ) | Commodity derivative transactions, net | | | 25,794 | | | | 3,634 | | Gain on asset sales | | | (9,832 | ) | | | (11,319 | ) | Gain on investment securities held in trusts | | | (154,723 | ) | | | (34,032 | ) | Cash collateral, net | | | (92,618 | ) | | | (8,827 | ) | Decrease (increase) in operating assets: | | | | | | | | | Receivables | | | (55,774 | ) | | | 106,574 | | Materials and supplies | | | 38,543 | | | | (35,498 | ) | Prepayments and other current assets | | | (35,315 | ) | | | (10,762 | ) | Increase (decrease) in operating liabilities: | | | | | | | | | Accounts payable | | | (72,181 | ) | | | (61,035 | ) | Accrued taxes | | | 23,846 | | | | (90,767 | ) | Accrued interest | | | 31,770 | | | | 15,420 | | Other | | | (43,369 | ) | | | (25,916 | ) | Net cash provided from operating activities | | | 881,811 | | | | 554,133 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 2,356,762 | | | | 537,375 | | Equity contribution from parent | | | - | | | | 280,000 | | Short-term borrowings, net | | | - | | | | 747,686 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (618,213 | ) | | | (460,902 | ) | Short-term borrowings, net | | | (1,164,823 | ) | | | - | | Common stock dividend payments | | | - | | | | (43,000 | ) | Other | | | (20,006 | ) | | | - | | Net cash provided from financing activities | | | 553,720 | | | | 1,061,159 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (842,600 | ) | | | (1,417,205 | ) | Proceeds from asset sales | | | 16,129 | | | | 15,218 | | Sales of investment securities held in trusts | | | 2,152,717 | | | | 596,291 | | Purchases of investment securities held in trusts | | | (2,175,135 | ) | | | (624,899 | ) | Loans to associated companies, net | | | (298,841 | ) | | | (64,142 | ) | Restricted funds for debt redemption | | | - | | | | (81,640 | ) | Other | | | (20,882 | ) | | | (38,915 | ) | Net cash used for investing activities | | | (1,168,612 | ) | | | (1,615,292 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | 266,919 | | | | - | | Cash and cash equivalents at beginning of period | | | 39 | | | | 2 | | Cash and cash equivalents at end of period | | $ | 266,958 | | | $ | 2 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they related to FirstEnergy Solutions Corp. are an | | integral part of these balance sheets. | | | | | | | | |
Expenses –
The $242 million increase in total expenses was due to the following:
| · | Purchased power costs were $4 million lower in the first three months of 2009 due to reduced volumes and an increase in the amount of NUG costs deferred, partially offset by increased unit costs. The increased unit costs reflected higher JCP&L costs resulting from the BGS auction. JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers and costs incurred under NUG agreements exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. The following table summarizes the sources of changes in purchased power costs:
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OHIO EDISON COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | | | | | | | | | | | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 575,377 | | | $ | 671,761 | | | $ | 1,942,612 | | | $ | 1,877,300 | | Excise and gross receipts tax collections | | | 27,127 | | | | 30,500 | | | | 81,055 | | | | 87,165 | | Total revenues | | | 602,504 | | | | 702,261 | | | | 2,023,667 | | | | 1,964,465 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power from affiliates | | | 200,506 | | | | 313,912 | | | | 847,712 | | | | 913,647 | | Purchased power from non-affiliates | | | 161,732 | | | | 35,462 | | | | 397,875 | | | | 83,962 | | Other operating costs | | | 102,463 | | | | 146,048 | | | | 372,231 | | | | 423,993 | | Provision for depreciation | | | 22,407 | | | | 14,997 | | | | 65,916 | | | | 57,904 | | Amortization of regulatory assets, net | | | 17,404 | | | | 42,582 | | | | 59,910 | | | | 87,664 | | General taxes | | | 45,164 | | | | 49,255 | | | | 138,187 | | | | 144,097 | | Total expenses | | | 549,676 | | | | 602,256 | | | | 1,881,831 | | | | 1,711,267 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 52,828 | | | | 100,005 | | | | 141,836 | | | | 253,198 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Investment income | | | 20,285 | | | | 19,323 | | | | 39,796 | | | | 45,866 | | Miscellaneous income (expense) | | | 237 | | | | (938 | ) | | | 2,108 | | | | (4,716 | ) | Interest expense | | | (22,961 | ) | | | (17,309 | ) | | | (67,717 | ) | | | (51,851 | ) | Capitalized interest | | | 231 | | | | 55 | | | | 730 | | | | 324 | | Total other income (expense) | | | (2,208 | ) | | | 1,131 | | | | (25,083 | ) | | | (10,377 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 50,620 | | | | 101,136 | | | | 116,753 | | | | 242,821 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 15,885 | | | | 28,501 | | | | 36,742 | | | | 77,122 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 34,735 | | | | 72,635 | | | | 80,011 | | | | 165,699 | | | | | | | | | | | | | | | | | | | Noncontrolling interest income | | | 140 | | | | 151 | | | | 429 | | | | 464 | | | | | | | | | | | | | | | | | | | EARNINGS AVAILABLE TO PARENT | | $ | 34,595 | | | $ | 72,484 | | | $ | 79,582 | | | $ | 165,235 | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 34,735 | | | $ | 72,635 | | | $ | 80,011 | | | $ | 165,699 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (49,043 | ) | | | (3,994 | ) | | | 46,559 | | | | (11,982 | ) | Change in unrealized gain on available-for-sale securities | | | (7,695 | ) | | | (9,936 | ) | | | (9,676 | ) | | | (20,310 | ) | Other comprehensive income (loss) | | | (56,738 | ) | | | (13,930 | ) | | | 36,883 | | | | (32,292 | ) | Income tax expense (benefit) related to other comprehensive income | | | (21,924 | ) | | | (5,105 | ) | | | 15,915 | | | | (11,931 | ) | Other comprehensive income (loss), net of tax | | | (34,814 | ) | | | (8,825 | ) | | | 20,968 | | | | (20,361 | ) | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) | | | (79 | ) | | | 63,810 | | | | 100,979 | | | | 145,338 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE | | | | | | | | | | | | | | | | | TO NONCONTROLLING INTEREST | | | 140 | | | | 151 | | | | 429 | | | | 464 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT | | $ | (219 | ) | | $ | 63,659 | | | $ | 100,550 | | | $ | 144,874 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | | | | | of these statements. | | | | | | | | | | | | | | | | |
Source of Change in Purchased Power | | Increase (Decrease) | | | | (In millions) | | Purchases from non-affiliates: | | | | | Change due to increased unit costs | | $ | 120 | | Change due to decreased volumes | | | (103 | ) | | | | 17 | | Purchases from FES: | | | | | Change due to decreased unit costs | | | (9 | ) | Change due to increased volumes | | | 22 | | | | | 13 | | | | | | | Increase in NUG costs deferred | | | (34 | ) | Net Decrease in Purchased Power Costs | | $ | (4 | ) |
| · | An increase in other operating expenses of $34 million resulted from economic development obligations, in accordance with the PUCO-approved ESP, and energy efficiency obligations. |
· | An increase in employee benefit costs of $30 million and organizational restructuring costs of $5 million were offset by reductions in contractor costs of $19 million, transmission expense of $11 million and materials and supplies costs of $5 million.
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| · | An increase of $157 million in amortization of regulatory assets in 2009 was due to the ESP-related impairment of CEI’s regulatory assets ($216 million), partially offset by the cessation of transition cost amortization for OE and TE ($68 million). |
| · | The deferral of new regulatory assets decreased by $57 million during the first three months of 2009 primarily due to lower PJM transmission cost deferrals ($25 million) and the cessation in 2009 of RCP distribution cost deferrals by the Ohio Companies ($35 million). |
· | Depreciation expense increased $3 million due to property additions since the first quarter of 2008. |
· | General taxes decreased $5 million primarily due to lower gross receipts taxes on reduced revenues. |
Other Expense –
Other expense increased $23 million in 2009 compared to the first three months of 2008, due to lower investment income of $16 million resulting from the repayment of notes receivable from affiliates and higher interest expense (net of capitalized interest) of $7 million due to $600 million of senior notes issued by JCP&L and Met-Ed in January 2009.
Competitive Energy Services – First Quarter 2009 Compared with First Quarter 2008
Net income for this segment was $155 million in the first three months of 2009 compared to $87 million in the same period in 2008. The $68 million increase in net income reflected an increase in gross generation margin, partially offset by higher operating costs.
Revenues –
Total revenues increased $123 million in the first three months of 2009 compared to the same period in 2008. This increase primarily resulted from higher unit prices on affiliated generation sales to the Ohio Companies and increased non-affiliated wholesale sales, partially offset by lower retail sales.
The increase in reported segment revenues resulted from the following sources:
OHIO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 329,745 | | | $ | 146,343 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $6,113,000 and $6,065,000, respectively, | | | | | | for uncollectible accounts) | | | 217,775 | | | | 277,377 | | Associated companies | | | 163,407 | | | | 234,960 | | Other (less accumulated provisions of $17,000 and $7,000, respectively, | | | | | | | | | for uncollectible accounts) | | | 16,862 | | | | 14,492 | | Notes receivable from associated companies | | | 89,410 | | | | 222,861 | | Prepayments and other | | | 15,394 | | | | 5,452 | | | | | 832,593 | | | | 901,485 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,993,708 | | | | 2,903,290 | | Less - Accumulated provision for depreciation | | | 1,148,804 | | | | 1,113,357 | | | | | 1,844,904 | | | | 1,789,933 | | Construction work in progress | | | 32,292 | | | | 37,766 | | | | | 1,877,196 | | | | 1,827,699 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Long-term notes receivable from associated companies | | | 192,550 | | | | 256,974 | | Investment in lease obligation bonds | | | 230,025 | | | | 239,625 | | Nuclear plant decommissioning trusts | | | 121,638 | | | | 116,682 | | Other | | | 97,949 | | | | 100,792 | | | | | 642,162 | | | | 714,073 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Regulatory assets | | | 493,955 | | | | 575,076 | | Pension assets | | | 17,336 | | | | - | | Property taxes | | | 60,542 | | | | 60,542 | | Unamortized sale and leaseback costs | | | 36,378 | | | | 40,130 | | Other | | | 33,695 | | | | 33,710 | | | | | 641,906 | | | | 709,458 | | | | $ | 3,993,857 | | | $ | 4,152,715 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 2,719 | | | $ | 101,354 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 75,002 | | | | - | | Other | | | 1,052 | | | | 1,540 | | Accounts payable- | | | | | | | | | Associated companies | | | 61,507 | | | | 131,725 | | Other | | | 36,503 | | | | 26,410 | | Accrued taxes | | | 73,666 | | | | 77,592 | | Accrued interest | | | 25,614 | | | | 25,673 | | Other | | | 127,056 | | | | 85,209 | | | | | 403,119 | | | | 449,503 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | | 60 shares outstanding | | | 1,228,463 | | | | 1,224,416 | | Accumulated other comprehensive loss | | | (163,417 | ) | | | (184,385 | ) | Retained earnings | | | 183,605 | | | | 254,023 | | Total common stockholder's equity | | | 1,248,651 | | | | 1,294,054 | | Noncontrolling interest | | | 6,975 | | | | 7,106 | | Total equity | | | 1,255,626 | | | | 1,301,160 | | Long-term debt and other long-term obligations | | | 1,161,237 | | | | 1,122,247 | | | | | 2,416,863 | | | | 2,423,407 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 699,399 | | | | 653,475 | | Accumulated deferred investment tax credits | | | 11,969 | | | | 13,065 | | Asset retirement obligations | | | 84,600 | | | | 80,647 | | Retirement benefits | | | 179,549 | | | | 308,450 | | Other | | | 198,358 | | | | 224,168 | | | | | 1,173,875 | | | | 1,279,805 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 3,993,857 | | | $ | 4,152,715 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of | | these balance sheets. | | | | | | | | |
| | Three Months Ended | | | | | | March 31 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Non-Affiliated Generation Sales: | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | Total Non-Affiliated Generation Sales | | | | | | | | | | ) | Affiliated Generation Sales | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | |
The lower retail revenues reflect reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in Ohio. Higher non-affiliated wholesale revenues resulted from higher PJM capacity prices and increased sales volumes in the MISO market, partially offset by lower unit prices and volumes in PJM.
The increased affiliated company generation revenues were due to higher unit prices for sales to the Ohio Companies under their CBP, partially offset by lower unit prices to the Pennsylvania Companies and an overall decrease in affiliated sales volumes. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. FES supplied less power to the Ohio Companies in the first quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP process. The amount of power FES will supply to the Ohio Companies for periods beginning on or after June 1, 2009 will be determined by the extent to which FES is successful in bidding in the upcoming CBP, which is currently scheduled to begin on May 13, 2009.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| | | | Source of Change in Non-Affiliated Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 57.0% decrease in sales volumes | | $ | (91 | ) | Change in prices | | | | | | | | | ) | Wholesale: | | | | | Effect of 33.9% increase in sales volumes | | | 44 | | Change in prices | | | | | | | | | | Net Decrease in Non-Affiliated Generation Revenues | | | | ) |
Source of Change in Affiliated Generation Revenues | | | | | | (In millions) | | Ohio Companies: | | | | | Effect of 24.6% decrease in sales volumes | | $ | (142 | ) | Change in prices | | | | | | | | | | Pennsylvania Companies: | | | | | Effect of 11.1% increase in sales volumes | | | 22 | | Change in prices | | | | ) | | | | | | Net Increase in Affiliated Generation Revenues | | | | |
OHIO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 80,011 | | | $ | 165,699 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 65,916 | | | | 57,904 | | Amortization of regulatory assets, net | | | 59,910 | | | | 87,664 | | Purchased power cost recovery reconciliation | | | 15,372 | | | | - | | Amortization of lease costs | | | 28,394 | | | | 28,535 | | Deferred income taxes and investment tax credits, net | | | 32,658 | | | | 17,267 | | Accrued compensation and retirement benefits | | | (3,542 | ) | | | (41,190 | ) | Accrued regulatory obligations | | | 19,172 | | | | - | | Electric service prepayment programs | | | (4,634 | ) | | | (31,895 | ) | Cash collateral from suppliers | | | 6,469 | | | | - | | Pension trust contributions | | | (103,035 | ) | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 128,688 | | | | (26,009 | ) | Prepayments and other current assets | | | (2,553 | ) | | | 2,065 | | Decrease in operating liabilities- | | | | | | | | | Accounts payable | | | (60,125 | ) | | | (27,463 | ) | Accrued taxes | | | (17,196 | ) | | | (27,776 | ) | Accrued interest | | | (59 | ) | | | (8,162 | ) | Other | | | (8,596 | ) | | | (1,307 | ) | Net cash provided from operating activities | | | 236,850 | | | | 195,332 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 100,000 | | | | - | | Short-term borrowings, net | | | 74,514 | | | | 189,148 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (101,088 | ) | | | (175,583 | ) | Dividend Payments- | | | | | | | | | Common stock | | | (150,000 | ) | | | (315,000 | ) | Other | | | (2,138 | ) | | | (445 | ) | Net cash used for financing activities | | | (78,712 | ) | | | (301,880 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (108,253 | ) | | | (135,450 | ) | Sales of investment securities held in trusts | | | 207,280 | | | | 115,988 | | Purchases of investment securities held in trusts | | | (214,592 | ) | | | (121,871 | ) | Loan repayments from associated companies, net | | | 134,975 | | | | 234,577 | | Cash investments | | | 7,070 | | | | 5,143 | | Other | | | (1,216 | ) | | | 8,144 | | Net cash provided from investing activities | | | 25,264 | | | | 106,531 | | | | | | | | | | | Net increase (decrease) in cash and cash equivalents | | | 183,402 | | | | (17 | ) | Cash and cash equivalents at beginning of period | | | 146,343 | | | | 732 | | Cash and cash equivalents at end of period | | $ | 329,745 | | | $ | 715 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral | | part of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | STATEMENTS OF INCOME | | (In thousands) | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 417,900 | | | $ | 505,425 | | | $ | 1,307,592 | | | $ | 1,342,327 | | Excise tax collections | | | 17,629 | | | | 18,652 | | | | 52,748 | | | | 53,447 | | Total revenues | | | 435,529 | | | | 524,077 | | | | 1,360,340 | | | | 1,395,774 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power from affiliates | | | 153,556 | | | | 211,417 | | | | 635,927 | | | | 587,203 | | Purchased power from non-affiliates | | | 87,689 | | | | 28 | | | | 208,849 | | | | 3,097 | | Other operating costs | | | 37,822 | | | | 66,342 | | | | 141,829 | | | | 194,119 | | Provision for depreciation | | | 17,753 | | | | 17,677 | | | | 53,885 | | | | 54,497 | | Amortization of regulatory assets | | | 39,313 | | | | 48,155 | | | | 325,630 | | | | 124,936 | | Deferral of new regulatory assets | | | - | | | | (16,176 | ) | | | (134,587 | ) | | | (71,443 | ) | General taxes | | | 37,752 | | | | 36,722 | | | | 112,749 | | | | 109,230 | | Total expenses | | | 373,885 | | | | 364,165 | | | | 1,344,282 | | | | 1,001,639 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 61,644 | | | | 159,912 | | | | 16,058 | | | | 394,135 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Investment income | | | 7,565 | | | | 8,390 | | | | 23,599 | | | | 25,972 | | Miscellaneous income (expense) | | | 645 | | | | (656 | ) | | | 3,437 | | | | 182 | | Interest expense | | | (34,740 | ) | | | (31,024 | ) | | | (100,819 | ) | | | (94,479 | ) | Capitalized interest | | | 27 | | | | 200 | | | | 145 | | | | 584 | | Total other expense | | | (26,503 | ) | | | (23,090 | ) | | | (73,638 | ) | | | (67,741 | ) | | | | | | | | | | | | | | | | | | INCOME (LOSS) BEFORE INCOME TAXES | | | 35,141 | | | | 136,822 | | | | (57,580 | ) | | | 326,394 | | | | | | | | | | | | | | | | | | | INCOME TAX EXPENSE (BENEFIT) | | | 9,755 | | | | 42,977 | | | | (25,290 | ) | | | 107,082 | | | | | | | | | | | | | | | | | | | NET INCOME (LOSS) | | | 25,386 | | | | 93,845 | | | | (32,290 | ) | | | 219,312 | | | | | | | | | | | | | | | | | | | Noncontrolling interest income | | | 418 | | | | 458 | | | | 1,295 | | | | 1,501 | | | | | | | | | | | | | | | | | | | EARNINGS (LOSS) AVAILABLE TO PARENT | | $ | 24,968 | | | $ | 93,387 | | | $ | (33,585 | ) | | $ | 217,811 | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME (LOSS) | | $ | 25,386 | | | $ | 93,845 | | | $ | (32,290 | ) | | $ | 219,312 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (48,024 | ) | | | (213 | ) | | | (154 | ) | | | (639 | ) | Unrealized loss on derivative hedges | | | (1,451 | ) | | | - | | | | (1,451 | ) | | | - | | Other comprehensive loss | | | (49,475 | ) | | | (213 | ) | | | (1,605 | ) | | | (639 | ) | Income tax expense (benefit) related to other comprehensive income | | | (17,854 | ) | | | (130 | ) | | | 1,452 | | | | (239 | ) | Other comprehensive loss, net of tax | | | (31,621 | ) | | | (83 | ) | | | (3,057 | ) | | | (400 | ) | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) | | | (6,235 | ) | | | 93,762 | | | | (35,347 | ) | | | 218,912 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE | | | | | | | | | | | | | | | | | TO NONCONTROLLING INTEREST | | | 418 | | | | 458 | | | | 1,295 | | | | 1,501 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT | | $ | (6,653 | ) | | $ | 93,304 | | | $ | (36,642 | ) | | $ | 217,411 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company are an | | integral part of these statements. | | | | | | | | | | | | | | | | |
Transmission revenues decreased $8 million due to decreased retail load in the MISO market ($14 million) partially offset by higher PJM congestion revenue ($6 million). Increased lease revenue represents NGC’s acquisition of the equity interests in the OE and TE Beaver Valley and Perry sale and leaseback transactions.THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 233 | | | $ | 226 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $6,603,000 and | | | | | | | | | $5,916,000, respectively, for uncollectible accounts) | | | 241,469 | | | | 276,400 | | Associated companies | | | 134,558 | | | | 113,182 | | Other | | | 2,260 | | | | 13,834 | | Notes receivable from associated companies | | | 23,698 | | | | 19,060 | | Prepayments and other | | | 158,993 | | | | 2,787 | | | | | 561,211 | | | | 425,489 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,283,729 | | | | 2,221,660 | | Less - Accumulated provision for depreciation | | | 880,334 | | | | 846,233 | | | | | 1,403,395 | | | | 1,375,427 | | Construction work in progress | | | 38,478 | | | | 40,651 | | | | | 1,441,873 | | | | 1,416,078 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 398,609 | | | | 425,715 | | Other | | | 264 | | | | 10,249 | | | | | 398,873 | | | | 435,964 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,688,521 | | | | 1,688,521 | | Regulatory assets | | | 592,206 | | | | 783,964 | | Property taxes | | | 71,500 | | | | 71,500 | | Other | | | 24,543 | | | | 10,818 | | | | | 2,376,770 | | | | 2,554,803 | | | | $ | 4,778,727 | | | $ | 4,832,334 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 150,738 | | | $ | 150,688 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 135,023 | | | | 227,949 | | Accounts payable- | | | | | | | | | Associated companies | | | 221,456 | | | | 106,074 | | Other | | | 16,573 | | | | 7,195 | | Accrued taxes | | | 77,298 | | | | 87,810 | | Accrued interest | | | 43,749 | | | | 13,932 | | Other | | | 49,267 | | | | 40,095 | | | | | 694,104 | | | | 633,743 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity | | | | | | | | | Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | | 67,930,743 shares outstanding | | | 884,415 | | | | 878,785 | | Accumulated other comprehensive loss | | | (137,914 | ) | | | (134,857 | ) | Retained earnings | | | 576,369 | | | | 859,954 | | Total common stockholder's equity | | | 1,322,870 | | | | 1,603,882 | | Noncontrolling interest | | | 20,196 | | | | 22,555 | | Total equity | | | 1,343,066 | | | | 1,626,437 | | Long-term debt and other long-term obligations | | | 1,871,401 | | | | 1,591,586 | | | | | 3,214,467 | | | | 3,218,023 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 662,422 | | | | 704,270 | | Accumulated deferred investment tax credits | | | 12,135 | | | | 13,030 | | Retirement benefits | | | 65,351 | | | | 128,738 | | Lease assignment payable to associated companies | | | 40,827 | | | | 40,827 | | Other | | | 89,421 | | | | 93,703 | | | | | 870,156 | | | | 980,568 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 4,778,727 | | | $ | 4,832,334 | | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | | Company are an integral part of these balance sheets. | | | | | | | | |
Expenses -
Total expenses decreased $4 million in the first three months of 2009 due to the following factors:
| · | Purchased power costs decreased $46 million due primarily to lower unit costs ($15 million) and reduced volume requirements ($31 million). |
· | Fossil fuel costs decreased $15 million due to decreased generation volumes ($53 million) partially offset by higher unit prices ($38 million). The increased unit prices primarily reflect increased fuel rates on existing coal contracts in the first quarter of 2009. |
· | Fossil operating costs decreased $4 million due to a $6 million decrease in contractor costs as a result of reduced maintenance activities, partially offset by organizational restructuring costs of $2 million. |
· | Other operating expenses increased $27 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies. |
· | Nuclear operating costs increased $16 million due to higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage. |
| · | Higher depreciation expense of $11 million was due to property additions since the first quarter of 2008. |
· | Transmission expense increased $7 million due to increased PJM charges. |
Other Expense –
Total other expense in the first three months of 2009 was $14 million higher than the first quarter of 2008, primarily due to a $23 million decrease in earnings from nuclear decommissioning trust investments reflecting impairments in the value of securities. This impact was partially offset by a decline in interest expense (net of capitalized interest) of $9 million.
Ohio Transitional Generation Services – First Quarter 2009 Compared with First Quarter 2008
Net income for this segment increased to $24 million in the first three months of 2009 from $23 million in the same period of 2008. Higher operating revenues were almost entirely offset by higher operating expenses, primarily for purchased power.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Three Months Ended | | | | | | March 31 | | | | Revenues by Type of Service | | 2009 | | 2008 | | Increase (Decrease) | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income (loss) | | $ | (32,290 | ) | | $ | 219,312 | | Adjustments to reconcile net income (loss) to net cash from operating activities- | | | | | | Provision for depreciation | | | 53,885 | | | | 54,497 | | Amortization of regulatory assets | | | 325,630 | | | | 124,936 | | Deferral of new regulatory assets | | | (134,587 | ) | | | (71,443 | ) | Purchased power cost recovery reconciliation | | | (3,478 | ) | | | - | | Deferred income taxes and investment tax credits, net | | | (41,939 | ) | | | 4,623 | | Accrued compensation and retirement benefits | | | 10,311 | | | | (3,291 | ) | Pension trust contribution | | | (89,789 | ) | | | - | | Electric service prepayment programs | | | (3,510 | ) | | | (17,551 | ) | Cash collateral from suppliers | | | 5,404 | | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 30,977 | | | | 43,927 | | Prepayments and other current assets | | | (633 | ) | | | (37 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (32,240 | ) | | | (4,443 | ) | Accrued taxes | | | (17,003 | ) | | | (19,613 | ) | Accrued interest | | | 29,816 | | | | 23,990 | | Other | | | 11,489 | | | | 5,647 | | Net cash provided from (used for) operating activities | | | 112,043 | | | | 360,554 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 298,398 | | | | - | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (558 | ) | | | (508 | ) | Short-term borrowings, net | | | (111,128 | ) | | | (176,354 | ) | Dividend Payments- | | | | | | | | | Common stock | | | (93,000 | ) | | | (150,000 | ) | Other | | | (6,161 | ) | | | (2,955 | ) | Net cash provided from (used for) financing activities | | | 87,551 | | | | (329,817 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (73,577 | ) | | | (97,326 | ) | Restricted cash | | | (155,573 | ) | | | - | | Loan repayments from (loans to) associated companies, net | | | (4,638 | ) | | | 30,624 | | Redemption of lessor notes | | | 37,072 | | | | 37,714 | | Other | | | (2,871 | ) | | | (1,744 | ) | Net cash used for investing activities | | | (199,587 | ) | | | (30,732 | ) | | | | | | | | | | Net increase in cash and cash equivalents | | | 7 | | | | 5 | | Cash and cash equivalents at beginning of period | | | 226 | | | | 232 | | Cash and cash equivalents at end of period | | $ | 233 | | | $ | 237 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating Company | | are an integral part of these statements. | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 206,086 | | | $ | 242,866 | | | $ | 663,082 | | | $ | 660,888 | | Excise tax collections | | | 7,422 | | | | 8,239 | | | | 21,448 | | | | 23,417 | | Total revenues | | | 213,508 | | | | 251,105 | | | | 684,530 | | | | 684,305 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power from affiliates | | | 86,278 | | | | 111,794 | | | | 342,166 | | | | 314,124 | | Purchased power from non-affiliates | | | 56,494 | | | | 15 | | | | 115,275 | | | | 1,833 | | Other operating costs | | | 30,238 | | | | 47,010 | | | | 110,722 | | | | 143,144 | | Provision for depreciation | | | 7,847 | | | | 7,682 | | | | 23,136 | | | | 24,648 | | Amortization of regulatory assets, net | | | 9,253 | | | | 25,878 | | | | 30,921 | | | | 57,840 | | General taxes | | | 13,205 | | | | 13,609 | | | | 39,804 | | | | 40,591 | | Total expenses | | | 203,315 | | | | 205,988 | | | | 662,024 | | | | 582,180 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 10,193 | | | | 45,117 | | | | 22,506 | | | | 102,125 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Investment income | | | 9,302 | | | | 5,580 | | | | 22,315 | | | | 17,285 | | Miscellaneous expense | | | (1,725 | ) | | | (1,523 | ) | | | (1,690 | ) | | | (4,982 | ) | Interest expense | | | (10,854 | ) | | | (5,832 | ) | | | (25,649 | ) | | | (17,445 | ) | Capitalized interest | | | 46 | | | | 19 | | | | 138 | | | | 144 | | Total other expense | | | (3,231 | ) | | | (1,756 | ) | | | (4,886 | ) | | | (4,998 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 6,962 | | | | 43,361 | | | | 17,620 | | | | 97,127 | | | | | | | | | | | | | | | | | | | INCOME TAX EXPENSE (BENEFIT) | | | (138 | ) | | | 12,174 | | | | 3,123 | | | | 27,614 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 7,100 | | | | 31,187 | | | | 14,497 | | | | 69,513 | | | | | | | | | | | | | | | | | | | Noncontrolling interest income | | | 14 | | | | 6 | | | | 17 | | | | 10 | | | | | | | | | | | | | | | | | | | EARNINGS AVAILABLE TO PARENT | | $ | 7,086 | | | $ | 31,181 | | | $ | 14,480 | | | $ | 69,503 | | | | | | | | | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 7,100 | | | $ | 31,187 | | | $ | 14,497 | | | $ | 69,513 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (24,201 | ) | | | (64 | ) | | | (5,052 | ) | | | (191 | ) | Change in unrealized gain on available-for-sale securities | | | (11,633 | ) | | | (247 | ) | | | (15,181 | ) | | | (767 | ) | Other comprehensive loss | | | (35,834 | ) | | | (311 | ) | | | (20,233 | ) | | | (958 | ) | Income tax benefit related to other comprehensive income | | | (13,187 | ) | | | (108 | ) | | | (5,982 | ) | | | (294 | ) | Other comprehensive loss, net of tax | | | (22,647 | ) | | | (203 | ) | | | (14,251 | ) | | | (664 | ) | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) | | | (15,547 | ) | | | 30,984 | | | | 246 | | | | 68,849 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE | | | | | | | | | | | | | | | | | TO NONCONTROLLING INTEREST | | | 14 | | | | 6 | | | | 17 | | | | 10 | | | | | | | | | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT | | $ | (15,561 | ) | | $ | 30,978 | | | $ | 229 | | | $ | 68,839 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral part of | | these statements. | | | | | | | | | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 196,834 | | | $ | 14 | | Receivables- | | | | | | | | | Customers | | | 485 | | | | 751 | | Associated companies | | | 44,103 | | | | 61,854 | | Other (less accumulated provisions of $207,000 and $203,000, | | | | | | respectively, for uncollectible accounts) | | | 19,349 | | | | 23,336 | | Notes receivable from associated companies | | | 101,562 | | | | 111,579 | | Prepayments and other | | | 4,864 | | | | 1,213 | | | | | 367,197 | | | | 198,747 | | UTILITY PLANT: | | | | | | | | | In service | | | 900,595 | | | | 870,911 | | Less - Accumulated provision for depreciation | | | 422,092 | | | | 407,859 | | | | | 478,503 | | | | 463,052 | | Construction work in progress | | | 8,621 | | | | 9,007 | | | | | 487,124 | | | | 472,059 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 124,329 | | | | 142,687 | | Long-term notes receivable from associated companies | | | 36,993 | | | | 37,233 | | Nuclear plant decommissioning trusts | | | 75,152 | | | | 73,500 | | Other | | | 1,603 | | | | 1,668 | | | | | 238,077 | | | | 255,088 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 500,576 | | | | 500,576 | | Regulatory assets | | | 77,128 | | | | 109,364 | | Property taxes | | | 22,970 | | | | 22,970 | | Other | | | 55,579 | | | | 51,315 | | | | | 656,253 | | | | 684,225 | | | | $ | 1,748,651 | | | $ | 1,610,119 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 222 | | | $ | 34 | | Accounts payable- | | | | | | | | | Associated companies | | | 27,454 | | | | 70,455 | | Other | | | 9,373 | | | | 4,812 | | Notes payable to associated companies | | | 9,673 | | | | 111,242 | | Accrued taxes | | | 23,660 | | | | 24,433 | | Lease market valuation liability | | | 36,900 | | | | 36,900 | | Other | | | 37,231 | | | | 22,489 | | | | | 144,513 | | | | 270,365 | | 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 | | | 177,992 | | | | 175,879 | | Accumulated other comprehensive loss | | | (47,623 | ) | | | (33,372 | ) | Retained earnings | | | 205,013 | | | | 190,533 | | Total common stockholder's equity | | | 482,392 | | | | 480,050 | | Noncontrolling interest | | | 2,692 | | | | 2,675 | | Total equity | | | 485,084 | | | | 482,725 | | Long-term debt and other long-term obligations | | | 608,669 | | | | 299,626 | | | | | 1,093,753 | | | | 782,351 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 70,865 | | | | 78,905 | | Accumulated deferred investment tax credits | | | 6,476 | | | | 6,804 | | Lease market valuation liability | | | 245,425 | | | | 273,100 | | Retirement benefits | | | 62,155 | | | | 73,106 | | Asset retirement obligations | | | 31,757 | | | | 30,213 | | Lease assignment payable to associated companies | | | 30,529 | | | | 30,529 | | Other | | | 63,178 | | | | 64,746 | | | | | 510,385 | | | | 557,403 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 1,748,651 | | | $ | 1,610,119 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | | integral part of these balance sheets. | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 14,497 | | | $ | 69,513 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 23,136 | | | | 24,648 | | Amortization of regulatory assets, net | | | 30,921 | | | | 57,840 | | Purchased power cost recovery reconciliation | | | 570 | | | | - | | Deferred rents and lease market valuation liability | | | (34,556 | ) | | | (32,918 | ) | Deferred income taxes and investment tax credits, net | | | (2,242 | ) | | | (4,163 | ) | Accrued compensation and retirement benefits | | | 3,039 | | | | (196 | ) | Accrued regulatory obligations | | | 4,841 | | | | - | | Electric service prepayment programs | | | (1,458 | ) | | | (8,566 | ) | Pension trust contribution | | | (21,590 | ) | | | - | | Cash collateral from suppliers | | | 2,830 | | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 24,561 | | | | 29,088 | | Prepayments and other current assets | | | 109 | | | | (556 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (13,440 | ) | | | (177,527 | ) | Accrued taxes | | | (5,057 | ) | | | (9,737 | ) | Accrued interest | | | 14,033 | | | | 4,663 | | Other | | | (4,264 | ) | | | (587 | ) | Net cash provided from (used for) operating activities | | | 35,930 | | | | (48,498 | ) | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 297,422 | | | | - | | Short-term borrowings, net | | | - | | | | 81,807 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (292 | ) | | | (26 | ) | Short-term borrowings, net | | | (101,569 | ) | | | - | | Dividend Payments- | | | | | | | | | Common stock | | | (25,000 | ) | | | (40,000 | ) | Other | | | (351 | ) | | | - | | Net cash provided from financing activities | | | 170,210 | | | | 41,781 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (33,005 | ) | | | (44,695 | ) | Loan repayments from associated companies, net | | | 10,256 | | | | 43,083 | | Redemption of lessor notes | | | 18,358 | | | | 11,989 | | Sales of investment securities held in trusts | | | 171,061 | | | | 28,774 | | Purchases of investment securities held in trusts | | | (173,214 | ) | | | (31,297 | ) | Other | | | (2,776 | ) | | | (1,135 | ) | Net cash provided from (used for) investing activities | | | (9,320 | ) | | | 6,719 | | | | | | | | | | | Net change in cash and cash equivalents | | | 196,820 | | | | 2 | | Cash and cash equivalents at beginning of period | | | 14 | | | | 22 | | Cash and cash equivalents at end of period | | $ | 196,834 | | | $ | 24 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | | integral part of these statements. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 854,108 | | | $ | 1,087,245 | | | $ | 2,312,089 | | | $ | 2,691,782 | | Excise tax collections | | | 14,128 | | | | 15,358 | | | | 37,890 | | | | 39,792 | | Total revenues | | | 868,236 | | | | 1,102,603 | | | | 2,349,979 | | | | 2,731,574 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power | | | 509,035 | | | | 720,996 | | | | 1,414,226 | | | | 1,751,854 | | Other operating costs | | | 84,495 | | | | 78,275 | | | | 241,241 | | | | 234,628 | | Provision for depreciation | | | 26,565 | | | | 23,205 | | | | 76,969 | | | | 70,030 | | Amortization of regulatory assets | | | 96,051 | | | | 102,954 | | | | 262,900 | | | | 280,980 | | General taxes | | | 18,344 | | | | 19,476 | | | | 48,427 | | | | 52,042 | | Total expenses | | | 734,490 | | | | 944,906 | | | | 2,043,763 | | | | 2,389,534 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 133,746 | | | | 157,697 | | | | 306,216 | | | | 342,040 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Miscellaneous income | | | 1,301 | | | | (565 | ) | | | 4,113 | | | | 459 | | Interest expense | | | (29,593 | ) | | | (25,747 | ) | | | (87,132 | ) | | | (75,051 | ) | Capitalized interest | | | 139 | | | | 257 | | | | 419 | | | | 963 | | Total other expense | | | (28,153 | ) | | | (26,055 | ) | | | (82,600 | ) | | | (73,629 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 105,593 | | | | 131,642 | | | | 223,616 | | | | 268,411 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 43,435 | | | | 55,752 | | | | 95,834 | | | | 115,623 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 62,158 | | | | 75,890 | | | | 127,782 | | | | 152,788 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (51,932 | ) | | | (3,449 | ) | | | (26,893 | ) | | | (10,347 | ) | Unrealized gain on derivative hedges | | | 69 | | | | 69 | | | | 207 | | | | 207 | | Other comprehensive loss | | | (51,863 | ) | | | (3,380 | ) | | | (26,686 | ) | | | (10,140 | ) | Income tax benefit related to other comprehensive income | | | (21,295 | ) | | | (1,469 | ) | | | (8,806 | ) | | | (4,408 | ) | Other comprehensive loss, net of tax | | | (30,568 | ) | | | (1,911 | ) | | | (17,880 | ) | | | (5,732 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 31,590 | | | $ | 73,979 | | | $ | 109,902 | | | $ | 147,056 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral | | part of these statements. | | | | | | | | | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | Setpember 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 1 | | | $ | 66 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,789,000 and $3,230,000 | | | | | | | | | respectively, for uncollectible accounts) | | | 339,025 | | | | 340,485 | | Associated companies | | | 147 | | | | 265 | | Other | | | 20,128 | | | | 37,534 | | Notes receivable - associated companies | | | 16,915 | | | | 16,254 | | Prepaid taxes | | | 94,140 | | | | 10,492 | | Other | | | 17,683 | | | | 18,066 | | | | | 488,039 | | | | 423,162 | | UTILITY PLANT: | | | | | | | | | In service | | | 4,427,994 | | | | 4,307,556 | | Less - Accumulated provision for depreciation | | | 1,597,831 | | | | 1,551,290 | | | | | 2,830,163 | | | | 2,756,266 | | Construction work in progress | | | 49,873 | | | | 77,317 | | | | | 2,880,036 | | | | 2,833,583 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear fuel disposal trust | | | 196,253 | | | | 181,468 | | Nuclear plant decommissioning trusts | | | 161,629 | | | | 143,027 | | Other | | | 2,174 | | | | 2,145 | | | | | 360,056 | | | | 326,640 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,810,936 | | | | 1,810,936 | | Regulatory assets | | | 949,814 | | | | 1,228,061 | | Other | | | 25,987 | | | | 29,946 | | | | | 2,786,737 | | | | 3,068,943 | | | | $ | 6,514,868 | | | $ | 6,652,328 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 30,227 | | | $ | 29,094 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 6,614 | | | | 121,380 | | Accounts payable- | | | | | | | | | Associated companies | | | 17,189 | | | | 12,821 | | Other | | | 153,704 | | | | 198,742 | | Accrued taxes | | | 3,994 | | | | 20,561 | | Accrued interest | | | 30,143 | | | | 9,197 | | Other | | | 113,232 | | | | 133,091 | | | | | 355,103 | | | | 524,886 | | CAPITALIZATION | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | | 13,628,447 shares outstanding | | | 136,284 | | | | 144,216 | | Other paid-in capital | | | 2,506,930 | | | | 2,644,756 | | Accumulated other comprehensive loss | | | (234,418 | ) | | | (216,538 | ) | Retained earnings | | | 196,358 | | | | 156,576 | | Total common stockholder's equity | | | 2,605,154 | | | | 2,729,010 | | Long-term debt and other long-term obligations | | | 1,810,367 | | | | 1,531,840 | | | | | 4,415,521 | | | | 4,260,850 | | NONCURRENT LIABILITIES: | | | | | | | | | Power purchase contract liability | | | 424,921 | | | | 531,686 | | Accumulated deferred income taxes | | | 700,187 | | | | 689,065 | | Nuclear fuel disposal costs | | | 196,454 | | | | 196,235 | | Asset retirement obligations | | | 99,954 | | | | 95,216 | | Retirement benefits | | | 131,621 | | | | 190,182 | | Other | | | 191,107 | | | | 164,208 | | | | | 1,744,244 | | | | 1,866,592 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 6,514,868 | | | $ | 6,652,328 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral | | part of these balance sheets. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 127,782 | | | $ | 152,788 | | Adjustments to reconcile net income to net cash from operating activities - | | | | | | | | | Provision for depreciation | | | 76,969 | | | | 70,030 | | Amortization of regulatory assets | | | 262,900 | | | | 280,980 | | Deferred purchased power and other costs | | | (106,340 | ) | | | (107,649 | ) | Deferred income taxes and investment tax credits, net | | | 40,989 | | | | 1,051 | | Accrued compensation and retirement benefits | | | 7,308 | | | | (32,087 | ) | Cash collateral received from (returned to) suppliers | | | (210 | ) | | | 23,138 | | Pension trust contribution | | | (100,000 | ) | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 18,984 | | | | (43,742 | ) | Prepaid taxes | | | (83,648 | ) | | | (62,148 | ) | Other current assets | | | 110 | | | | 234 | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (40,670 | ) | | | 36,099 | | Accrued taxes | | | (13,399 | ) | | | 2,082 | | Accrued interest | | | 20,946 | | | | 17,276 | | Tax collections payable | | | (9,714 | ) | | | (12,493 | ) | Other | | | 12,606 | | | | (466 | ) | Net cash provided from operating activities | | | 214,613 | | | | 325,093 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 299,619 | | | | - | | Short-term borrowings, net | | | - | | | | 12,236 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (20,570 | ) | | | (19,138 | ) | Common Stock | | | (150,000 | ) | | | - | | Short-term borrowings, net | | | (114,766 | ) | | | - | | Dividend Payments- | | | | | | | | | Common stock | | | (88,000 | ) | | | (186,000 | ) | Other | | | (2,275 | ) | | | - | | Net cash used for financing activities | | | (75,992 | ) | | | (192,902 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (121,342 | ) | | | (136,265 | ) | Proceeds from asset sales | | | - | | | | 20,000 | | Loans to associated companies, net | | | (660 | ) | | | 553 | | Sales of investment securities held in trusts | | | 338,684 | | | | 186,564 | | Purchases of investment securities held in trusts | | | (351,216 | ) | | | (199,699 | ) | Other | | | (4,152 | ) | | | (3,400 | ) | Net cash used for investing activities | | | (138,686 | ) | | | (132,247 | ) | | | | | | | | | | Net decrease in cash and cash equivalents | | | (65 | ) | | | (56 | ) | Cash and cash equivalents at beginning of period | | | 66 | | | | 94 | | Cash and cash equivalents at end of period | | $ | 1 | | | $ | 38 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | | are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | | | | | | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 424,901 | | | $ | 434,742 | | | $ | 1,194,609 | | | $ | 1,188,171 | | Gross receipts tax collections | | | 20,612 | | | | 20,793 | | | | 58,181 | | | | 59,669 | | Total revenues | | | 445,513 | | | | 455,535 | | | | 1,252,790 | | | | 1,247,840 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power from affiliates | | | 94,768 | | | | 81,846 | | | | 273,497 | | | | 233,496 | | Purchased power from non-affiliates | | | 142,495 | | | | 163,853 | | | | 389,705 | | | | 446,928 | | Other operating costs | | | 63,654 | | | | 126,659 | | | | 221,320 | | | | 350,704 | | Provision for depreciation | | | 13,262 | | | | 11,394 | | | | 38,320 | | | | 33,446 | | Amortization (deferral) of regulatory assets, net | | | 84,631 | | | | 3,680 | | | | 173,770 | | | | (10,162 | ) | General taxes | | | 22,540 | | | | 23,030 | | | | 66,509 | | | | 64,887 | | Total expenses | | | 421,350 | | | | 410,462 | | | | 1,163,121 | | | | 1,119,299 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 24,163 | | | | 45,073 | | | | 89,669 | | | | 128,541 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Interest income | | | 2,169 | | | | 4,016 | | | | 8,124 | | | | 14,368 | | Miscellaneous income | | | 1,068 | | | | 88 | | | | 2,982 | | | | 568 | | Interest expense | | | (14,380 | ) | | | (11,014 | ) | | | (42,502 | ) | | | (33,666 | ) | Capitalized interest | | | 47 | | | | 93 | | | | 124 | | | | 73 | | Total other expense | | | (11,096 | ) | | | (6,817 | ) | | | (31,272 | ) | | | (18,657 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 13,067 | | | | 38,256 | | | | 58,397 | | | | 109,884 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 2,324 | | | | 16,270 | | | | 21,027 | | | | 45,866 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 10,743 | | | | 21,986 | | | | 37,370 | | | | 64,018 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (31,365 | ) | | | (2,233 | ) | | | 557 | | | | (6,699 | ) | Unrealized gain on derivative hedges | | | 84 | | | | 84 | | | | 252 | | | | 252 | | Other comprehensive income (loss) | | | (31,281 | ) | | | (2,149 | ) | | | 809 | | | | (6,447 | ) | Income tax expense (benefit) related to other comprehensive income | | | (13,112 | ) | | | (971 | ) | | | 2,273 | | | | (2,912 | ) | Other comprehensive loss, net of tax | | | (18,169 | ) | | | (1,178 | ) | | | (1,464 | ) | | | (3,535 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME (LOSS) | | $ | (7,426 | ) | | $ | 20,808 | | | $ | 35,906 | | | $ | 60,483 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | | | | | | part of these statements. | | | | | | | | | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 124 | | | $ | 144 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,880,000 and $3,616,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 165,519 | | | | 159,975 | | Associated companies | | | 43,462 | | | | 17,034 | | Other | | | 11,472 | | | | 19,828 | | Notes receivable from associated companies | | | 18,032 | | | | 11,446 | | Prepaid taxes | | | 29,895 | | | | 6,121 | | Other | | | 4,650 | | | | 1,621 | | | | | 273,154 | | | | 216,169 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,141,513 | | | | 2,065,847 | | Less - Accumulated provision for depreciation | | | 800,750 | | | | 779,692 | | | | | 1,340,763 | | | | 1,286,155 | | Construction work in progress | | | 11,718 | | | | 32,305 | | | | | 1,352,481 | | | | 1,318,460 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 258,475 | | | | 226,139 | | Other | | | 981 | | | | 976 | | | | | 259,456 | | | | 227,115 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 416,499 | | | | 416,499 | | Regulatory assets | | | 403,690 | | | | 412,994 | | Power purchase contract asset | | | 186,661 | | | | 300,141 | | Other | | | 33,977 | | | | 31,031 | | | | | 1,040,827 | | | | 1,160,665 | | | | $ | 2,925,918 | | | $ | 2,922,409 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 128,500 | | | $ | 28,500 | | Short-term borrowings- | | | | | | | | | Associated companies | | | - | | | | 15,003 | | Other | | | - | | | | 250,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 26,817 | | | | 28,707 | | Other | | | 39,927 | | | | 55,330 | | Accrued taxes | | | 5,143 | | | | 16,238 | | Accrued interest | | | 11,756 | | | | 6,755 | | Other | | | 30,354 | | | | 30,647 | | | | | 242,497 | | | | 431,180 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 900,000 shares- | | | | | | | | | 859,500 shares outstanding | | | 1,197,007 | | | | 1,196,172 | | Accumulated other comprehensive loss | | | (142,448 | ) | | | (140,984 | ) | Accumulated deficit | | | (13,754 | ) | | | (51,124 | ) | Total common stockholder's equity | | | 1,040,805 | | | | 1,004,064 | | Long-term debt and other long-term obligations | | | 713,843 | | | | 513,752 | | | | | 1,754,648 | | | | 1,517,816 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 448,951 | | | | 387,757 | | Accumulated deferred investment tax credits | | | 7,427 | | | | 7,767 | | Nuclear fuel disposal costs | | | 44,378 | | | | 44,328 | | Asset retirement obligations | | | 177,335 | | | | 170,999 | | Retirement benefits | | | 31,753 | | | | 145,218 | | Power purchase contract liability | | | 151,815 | | | | 150,324 | | Other | | | 67,114 | | | | 67,020 | | | | | 928,773 | | | | 973,413 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 2,925,918 | | | $ | 2,922,409 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | | part of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 37,370 | | | $ | 64,018 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 38,320 | | | | 33,446 | | Amortization (deferral) of regulatory assets, net | | | 173,770 | | | | (10,162 | ) | Deferred costs recoverable as regulatory assets | | | (70,044 | ) | | | (9,673 | ) | Deferred income taxes and investment tax credits, net | | | 59,393 | | | | 39,919 | | Accrued compensation and retirement benefits | | | 6,712 | | | | (18,948 | ) | Pension trust contribution | | | (123,521 | ) | | | - | | Cash collateral | | | (6,800 | ) | | | - | | Decrease (Increase) in operating assets- | | | | | | | | | Receivables | | | (23,370 | ) | | | (19,751 | ) | Prepayments and other current assets | | | (22,614 | ) | | | (4,144 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (17,293 | ) | | | (9,250 | ) | Accrued taxes | | | (11,095 | ) | | | (13,285 | ) | Accrued interest | | | 5,001 | | | | 495 | | Other | | | 11,891 | | | | 13,510 | | Net cash provided from operating activities | | | 57,720 | | | | 66,175 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 300,000 | | | | 28,500 | | Short-term borrowings, net | | | - | | | | 29,959 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | - | | | | (28,640 | ) | Short-term borrowings, net | | | (265,003 | ) | | | - | | Other | | | (2,268 | ) | | | - | | Net cash provided from financing activities | | | 32,729 | | | | 29,819 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (73,106 | ) | | | (87,536 | ) | Sales of investment securities held in trusts | | | 88,802 | | | | 131,915 | | Purchases of investment securities held in trusts | | | (95,982 | ) | | | (140,429 | ) | Loans from (to) associated companies, net | | | (6,586 | ) | | | 1,163 | | Other | | | (3,597 | ) | | | (1,113 | ) | Net cash used for investing activities | | | (90,469 | ) | | | (96,000 | ) | | | | | | | | | | Net decrease in cash and cash equivalents | | | (20 | ) | | | (6 | ) | Cash and cash equivalents at beginning of period | | | 144 | | | | 135 | | Cash and cash equivalents at end of period | | $ | 124 | | | $ | 129 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | | part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS) | | (Unaudited) | | | | | | | | | | | | | | | | | Three Months Ended | | | Nine Months Ended | | | | September 30 | | | September 30 | | | | 2009 | | | 2008 | | | 2009 | | | 2008 | | | | (In thousands) | | REVENUES: | | | | | | | | | | | | | Electric sales | | $ | 340,246 | | | $ | 372,576 | | | $ | 1,028,420 | | | $ | 1,083,986 | | Gross receipts tax collections | | | 15,246 | | | | 17,200 | | | | 47,342 | | | | 52,704 | | Total revenues | | | 355,492 | | | | 389,776 | | | | 1,075,762 | | | | 1,136,690 | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | Purchased power from affiliates | | | 81,191 | | | | 68,743 | | | | 249,438 | | | | 214,775 | | Purchased power from non-affiliates | | | 144,777 | | | | 161,913 | | | | 397,260 | | | | 442,906 | | Other operating costs | | | 47,785 | | | | 54,727 | | | | 171,375 | | | | 175,904 | | Provision for depreciation | | | 15,038 | | | | 14,097 | | | | 45,074 | | | | 40,531 | | Amortization of regulatory assets, net | | | 17,201 | | | | 23,415 | | | | 44,090 | | | | 55,346 | | General taxes | | | 17,230 | | | | 20,285 | | | | 56,074 | | | | 60,485 | | Total expenses | | | 323,222 | | | | 343,180 | | | | 963,311 | | | | 989,947 | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 32,270 | | | | 46,596 | | | | 112,451 | | | | 146,743 | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | Miscellaneous income | | | 1,156 | | | | (93 | ) | | | 2,865 | | | | 774 | | Interest expense | | | (11,614 | ) | | | (14,934 | ) | | | (36,690 | ) | | | (45,157 | ) | Capitalized interest | | | 23 | | | | 57 | | | | 74 | | | | (679 | ) | Total other expense | | | (10,435 | ) | | | (14,970 | ) | | | (33,751 | ) | | | (45,062 | ) | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 21,835 | | | | 31,626 | | | | 78,700 | | | | 101,681 | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 6,039 | | | | 9,058 | | | | 29,393 | | | | 39,324 | | | | | | | | | | | | | | | | | | | NET INCOME | | | 15,796 | | | | 22,568 | | | | 49,307 | | | | 62,357 | | | | | | | | | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | | | | | | | | | Pension and other postretirement benefits | | | (79,579 | ) | | | (3,474 | ) | | | (47,224 | ) | | | (10,421 | ) | Unrealized gain on derivative hedges | | | 17 | | | | 16 | | | | 49 | | | | 48 | | Change in unrealized gain on available-for-sale securities | | | 19 | | | | 2 | | | | 3 | | | | (8 | ) | Other comprehensive loss | | | (79,543 | ) | | | (3,456 | ) | | | (47,172 | ) | | | (10,381 | ) | Income tax benefit related to other comprehensive loss | | | (33,141 | ) | | | (1,510 | ) | | | (16,986 | ) | | | (4,536 | ) | Other comprehensive loss, net of tax | | | (46,402 | ) | | | (1,946 | ) | | | (30,186 | ) | | | (5,845 | ) | | | | | | | | | | | | | | | | | | TOTAL COMPREHENSIVE INCOME (LOSS) | | $ | (30,606 | ) | | $ | 20,622 | | | $ | 19,121 | | | $ | 56,512 | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an integral part | | of these statements. | | | | | | | | | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | September 30, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 9 | | | $ | 23 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $2,844,000 and $3,121,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 124,178 | | | | 146,831 | | Associated companies | | | 98,061 | | | | 65,610 | | Other | | | 14,116 | | | | 26,766 | | Notes receivable from associated companies | | | 14,186 | | | | 14,833 | | Prepaid taxes | | | 41,916 | | | | 16,310 | | Other | | | 641 | | | | 1,517 | | | | | 293,107 | | | | 271,890 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,397,432 | | | | 2,324,879 | | Less - Accumulated provision for depreciation | | | 891,835 | | | | 868,639 | | | | | 1,505,597 | | | | 1,456,240 | | Construction work in progress | | | 28,729 | | | | 25,146 | | | | | 1,534,326 | | | | 1,481,386 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 137,008 | | | | 115,292 | | Non-utility generation trusts | | | 119,163 | | | | 116,687 | | Other | | | 290 | | | | 293 | | | | | 256,461 | | | | 232,272 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 768,628 | | | | 768,628 | | Power purchase contract asset | | | 23,979 | | | | 119,748 | | Regulatory assets | | | 3,433 | | | | - | | Other | | | 18,814 | | | | 18,658 | | | | | 814,854 | | | | 907,034 | | | | $ | 2,898,748 | | | $ | 2,892,582 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 80,000 | | | $ | 145,000 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 41,632 | | | | 31,402 | | Other | | | - | | | | 250,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 27,126 | | | | 63,692 | | Other | | | 41,210 | | | | 48,633 | | Accrued taxes | | | 6,104 | | | | 13,264 | | Accrued interest | | | 10,561 | | | | 13,131 | | Other | | | 27,237 | | | | 31,730 | | | | | 233,870 | | | | 596,852 | | 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 | | | 913,374 | | | | 912,441 | | Accumulated other comprehensive loss | | | (158,183 | ) | | | (127,997 | ) | Retained earnings | | | 75,420 | | | | 76,113 | | Total common stockholder's equity | | | 919,163 | | | | 949,109 | | Long-term debt and other long-term obligations | | | 1,096,745 | | | | 633,132 | | | | | 2,015,908 | | | | 1,582,241 | | NONCURRENT LIABILITIES: | | | | | | | | | Regulatory liabilities | | | - | | | | 136,579 | | Accumulated deferred income taxes | | | 220,925 | | | | 169,807 | | Retirement benefits | | | 168,767 | | | | 172,718 | | Asset retirement obligations | | | 90,334 | | | | 87,089 | | Power purchase contract liability | | | 108,160 | | | | 83,600 | | Other | | | 60,784 | | | | 63,696 | | | | | 648,970 | | | | 713,489 | | COMMITMENTS AND CONTINGENCIES (Note 9) | | | | | | | | | | | $ | 2,898,748 | | | $ | 2,892,582 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company | | are an integral part of these balance sheets. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Nine Months Ended | | | | September 30 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 49,307 | | | $ | 62,357 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 45,074 | | | | 40,531 | | Amortization of regulatory assets, net | | | 44,090 | | | | 55,346 | | Deferred costs recoverable as regulatory assets | | | (76,953 | ) | | | (20,304 | ) | Deferred income taxes and investment tax credits, net | | | 56,144 | | | | 68,377 | | Accrued compensation and retirement benefits | | | 6,271 | | | | (21,190 | ) | Pension trust contribution | | | (60,000 | ) | | | - | | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 3,687 | | | | (42,971 | ) | Prepayments and other current assets | | | (24,730 | ) | | | (28,730 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (8,988 | ) | | | (8,437 | ) | Accrued taxes | | | (7,015 | ) | | | (11,521 | ) | Accrued interest | | | (2,570 | ) | | | 867 | | Other | | | 13,392 | | | | 14,663 | | Net cash provided from operating activities | | | 37,709 | | | | 108,988 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 498,583 | | | | 45,000 | | Short-term borrowings, net | | | - | | | | 65,590 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (100,000 | ) | | | (45,332 | ) | Short-term borrowings, net | | | (239,770 | ) | | | - | | Dividend Payments- | | | | | | | | | Common stock | | | (85,000 | ) | | | (65,000 | ) | Other | | | (3,865 | ) | | | - | | Net cash provided from financing activities | | | 69,948 | | | | 258 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (92,070 | ) | | | (94,810 | ) | Loan repayments from associated companies, net | | | 647 | | | | 907 | | Sales of investment securities held in trust | | | 80,986 | | | | 84,499 | | Purchases of investment securities held in trust | | | (91,105 | ) | | | (96,950 | ) | Other | | | (6,129 | ) | | | (2,902 | ) | Net cash used for investing activities | | | (107,671 | ) | | | (109,256 | ) | | | | | | | | | | Net decrease in cash and cash equivalents | | | (14 | ) | | | (10 | ) | Cash and cash equivalents at beginning of period | | | 23 | | | | 46 | | Cash and cash equivalents at end of period | | $ | 9 | | | $ | 36 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are an | | integral part of these statements. | | | | | | | | |
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through November 6, 2009, the date the financial statements were issued.
These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 7) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) 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.
The consolidated financial statements as of September 30, 2009 and for the three-month and nine-month periods ended September 30, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated November 6, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a "report" or a "part" of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.
2. EARNINGS PER SHARE
Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
| | Three Months Ended | | Nine Months Ended | | Reconciliation of Basic and Diluted Earnings per Share | | | | | | of Common Stock | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions, except per share amounts) | | Earnings available to FirstEnergy Corp. | | $ | 234 | | $ | 471 | | $ | 768 | | $ | 1,010 | | | | | | | | | | | | | | | | Average shares of common stock outstanding - Basic | | | 304 | | | 304 | | | 304 | | | 304 | | Assumed exercise of dilutive stock options and awards | | | 2 | | | 3 | | | 2 | | | 3 | | Average shares of common stock outstanding - Diluted | | | 306 | | | 307 | | | 306 | | | 307 | | | | | | | | | | | | | | | | Basic earnings per share of common stock | | $ | .77 | | $ | 1.55 | | $ | 2.52 | | $ | 3.32 | | Diluted earnings per share of common stock | | $ | .77 | | $ | 1.54 | | $ | 2.51 | | $ | 3.29 | |
3. GOODWILL
In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. FirstEnergy's 2009 annual evaluation was completed in the third quarter of 2009 with no impairment indicated.
4. FAIR VALUE OF FINANCIAL INSTRUMENTS
(A) | LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS |
All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of September 30, 2009 and December 31, 2008:
| | | | | | | | Carrying | | Fair | | Carrying | | Fair | | | | | | | | | | | | | | (In millions) | | | | | 13,675 | | | 14,483 | | | | | | | | | | | 4,233 | | | 4,304 | | | | | | | | | | | 1,169 | | | 1,318 | | | | | | | | | | | 1,900 | | | 2,033 | | | | | | | | | | | 600 | | | 656 | | | | | | | | | | | 1,849 | | | 1,977 | | | | | | | | | | | 842 | | | 911 | | | | | | | | | | | 1,179 | | | 1,221 | | | | | | | |
The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FES and the Utilities.
All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities, available-for-sale securities, and notes receivable.
FES and the Utilities periodically evaluate their investments for other-than-temporary impairment. They first consider their intent and ability to hold an equity investment until recovery and then consider, among other factors, the duration and the extent to which the security's fair value has been less than cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FES and the Utilities consider their intent to hold the security, the likelihood that they will be required to sell the security before recovery of its cost basis, and the likelihood of recovery of the security's entire amortized cost basis.
Available-For-Sale Securities
FES and the Utilities hold debt and equity securities within their nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered as available-for-sale at fair market value. FES and the Utilities have no securities held for trading purposes.
The following table summarizes the priceamortized cost basis, unrealized gains and volume factors contributing to the increaselosses and fair values of investments in sales revenues from retail customers:available-for-sale securities as of September 30, 2009 and December 31, 2008:
Source of Change in Retail Generation Revenues | | | | | | (In millions) | | Effect of 5.0% increase in sales volumes | | $ | 30 | | Change in prices | | | | | Total Increase in Retail Generation Revenues | | | | |
| | September 30, 2009(1) | | December 31, 2008(2) | | | | Cost | | Unrealized | | Unrealized | | Fair | | Cost | | Unrealized | | Unrealized | | Fair | | | | Basis | | Gains | | Losses | | Value | | Basis | | Gains | | Losses | | Value | | Debt securities | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (1) Excludes cash balances of $1,291 million at FirstEnergy, $1,094 million at FES, $2 million at JCP&L, $120 million at OE, $5 million at Penelec and $75 million at TE. (2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed. (3) Includes fair values as of September 30, 2009 and December 31, 2008 of $557 million and $953 million of government obligations, $44 million and $175 million of corporate debt and $1 million and $6 million of mortgage backed securities. |
The increase in generation sales was primarily due to reduced customer shopping as most of the Ohio Companies’ customers returned to PLR service in December 2008 due to the termination of certain government aggregation programs in Ohio. Average prices increased primarily due to an increase in the Ohio Companies’ fuel cost recovery rider that became effective in January 2009.
Increased transmission revenue of $17 million resulted from higher sales volumes and a PUCO-approved transmission tariff increase that was effective in mid-2008. The difference between transmission revenues accrued and transmission expenses incurred is deferred, resulting in no material impact to current period earnings.
Expenses -
Purchased power costs were $310 million higher due primarily to higher unit costs and volumes. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase | | | | (In millions) | | Purchases: | | | | | Change due to increased unit costs | | $ | 284 | | Change due to increased volumes | | | 26 | | | | $ | 310 | |
The increase in purchased volumes was due to the higher retail generation sales requirements described above. The higher unit costs reflect the implementation of the Ohio Companies’ CBP for their power supply for retail customers.
Other operating expenses decreased $59 million due to lower MISO transmission-related expenses and increased intersegment credits related to the Ohio Companies’ generation leasehold interests. The deferral of regulatory assets increased by $45 million due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by reduced MISO transmission cost deferrals. The difference between transmission revenues accrued and transmission expenses incurred is deferred or amortized, resulting in no material impact to current period earnings.
Other – First Quarter 2009 Compared with First Quarter 2008
FirstEnergy’s 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 $10 million decrease in FirstEnergy’s net income in the first three months of 2009 compared to the same period in 2008. The decrease resulted primarilyProceeds from the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes), partially offset by the favorable resolutioninvestments in 2009 of income tax issues relating to prior years ($13 million).
CAPITAL RESOURCES AND LIQUIDITY
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligationsavailable-for-sale securities, realized gains and losses on those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturitiessales, and interest and dividend payments. income for the nine-month period ended September 30, 2009 were as follows:
| | FirstEnergy | | FES | | OE | | TE | | JCP&L | | Met-Ed | | Penelec | | | | (In millions) | | | | $ | 3,040 | | $ | 2,153 | | $ | 207 | | $ | 171 | | $ | 339 | | $ | 89 | | $ | 81 | | | | | 186 | | | 162 | | | 11 | | | 7 | | | 4 | | | 1 | | | 1 | | | | | 96 | | | 62 | | | 3 | | | - | | | 11 | | | 13 | | | 7 | | Interest and dividend income | | | 47 | | | 22 | | | 4 | | | 2 | | | 10 | | | 5 | | | 4 | |
Unrealized gains applicable to the decommissioning trusts of OE, TE and FES are recognized in OCI as fluctuations in fair value will eventually impact earnings. The decommissioning trusts of JCP&L, Met-Ed and Penelec are subject to regulatory accounting. Net unrealized gains and losses are recorded as regulatory assets or liabilities since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers.
The investment policy for the nuclear decommissioning trust funds restricts or limits the ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, preferred stocks, securities convertible into common stock and securities of the trust fund's custodian or managers and their parents or subsidiaries.
During the three-month period ended September 30, 2009, FES recognized $135 million of realized gains resulting from the sale of securities held in the nuclear decommissioning trust.
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 (except for investments of $271 million and $293 million that are not required to be disclosed) as of September 30, 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.December 31, 2008:
| | September 30, 2009 | | December 31, 2008 | | | | Cost | | Unrealized | | Unrealized | | Fair | | Cost | | Unrealized | | Unrealized | | Fair | | | | Basis | | Gains | | Losses | | Value | | Basis | | Gains | | Losses | | Value | | Debt securities | | (In millions) | | | | $ | 621 | | $ | 91 | | $ | - | | $ | 712 | | $ | 673 | | $ | 14 | | $ | 13 | | $ | 674 | | | | | 230 | | | 57 | | | - | | | 287 | | | 240 | | | - | | | 13 | | | 227 | | | | | 389 | | | 34 | | | - | | | 423 | | | 426 | | | 9 | | | - | | | 435 | |
AsThe following table provides the approximate fair value and related carrying amounts of March 31, 2009, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($2.4 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debtnotes receivable as of MarchSeptember 30, 2009 and December 31, 2009, included the following (in millions):2008:
Currently Payable Long-term Debt | | | | | | PCRBs supported by bank LOCs(1) | | $ | 1,636 | | | FGCO and NGC unsecured PCRBs(1) | | | 82 | | | Penelec unsecured notes(2) | | | 100 | | | CEI secured notes(3) | | | 150 | | | Met-Ed secured notes(4) | | | 100 | | | NGC collateralized lease obligation bonds | | | 36 | | | Sinking fund requirements | | | 40 | | | | | $ | 2,144 | | | | | | | | | (1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Matured in April 2009. (3) Mature in November 2009. (4) Mature in March 2010. |
| | | | | | | | Carrying | | Fair | | Carrying | | Fair | | | | | | | | | | | | Notes receivable | | (In millions) | | FirstEnergy | | $ | 45 | | $ | 42 | | $ | 45 | | $ | 44 | | FES | | | 4 | | | 4 | | | 75 | | | 74 | | OE | | | 193 | | | 234 | | | 257 | | | 294 | | | | | 161 | | | 180 | | | | | | | |
Short-Term BorrowingsThe fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2009 to 2040.
FirstEnergy had approximately $2.4 billion(C) | RECURRING FAIR VALUE MEASUREMENTS |
FirstEnergy's valuation techniques, including the three levels of short-term borrowingsthe fair value hierarchy, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008.
The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31,September 30, 2009 and December 31, 2008. FirstEnergy, along with certainAssets and liabilities are classified in their entirety based on the lowest level of its subsidiaries, have accessinput that is significant to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3%fair value measurement. FirstEnergy's assessment of the total commitment. Assignificance of May 1, 2009, FirstEnergy had $720 million of bank credit facilities in additiona particular input to the $2.75 billion revolving credit facility. Also, an aggregatefair value measurement requires judgment and may affect the fair valuation of $550 million of accounts receivable financing facilities throughassets and liabilities and their placement within the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. FirstEnergy’s available liquidity as of May 1, 2009, is summarized in the following table: Company | | Type | | Maturity | | Commitment | | Available Liquidity as of May 1, 2009 | | | | | | | | (In millions) | | FirstEnergy(1) | | Revolving | | Aug. 2012 | | $ | 2,750 | | $ | 227 | | FirstEnergy and FES | | Revolving | | May 2009 | | | 300 | | | 300 | | FirstEnergy | | Bank lines | | Various(2) | | | 120 | | | 20 | | FGCO | | Term loan | | Oct. 2009(3) | | | 300 | | | 300 | | Ohio and Pennsylvania Companies | | Receivables financing | | Various(4) | | | 550 | | | 416 | | | | | | Subtotal | | $ | 4,020 | | $ | 1,263 | | | | | | Cash | | | - | | | 698 | | | | | | Total | | $ | 4,020 | | $ | 1,961 | | (1) FirstEnergy Corp. and subsidiary borrowers. (2) $100 million matures March 31, 2011; $20 million uncommitted line of credit has no maturity date. (3) Drawn amounts are payable within 30 days and may not be re-borrowed. (4) $180 million expires December 18, 2009, $370 million expires February 22, 2010. | |
fair value hierarchy levels.
Revolving Credit FacilityRecurring Fair Value Measures as of September 30, 2009 | | | Level 1 - Assets | | | Level 1 - Liabilities | | (In millions) | | | Derivatives | | Available-for- Sale Securities(1) | | Other Investments | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | $ | - | $ | 278 | $ | - | $ | 278 | | $ | 15 | $ | - | $ | 15 | FES | | - | | 1 | | - | | 1 | | | 15 | | - | | 15 | OE | | - | | - | | - | | - | | | - | | - | | - | JCP&L | | - | | 81 | | - | | 81 | | | - | | - | | - | Met-Ed | | - | | 125 | | - | | 125 | | | - | | - | | - | Penelec | | - | | 71 | | - | | 71 | | | - | | - | | - | | | | | | | | | | | | | | | | | | | Level 2 - Assets | | | Level 2 - Liabilities | | | Derivatives | | Available-for- Sale Securities(1) | | Other Investments | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | $ | 32 | $ | 1,896 | $ | 78 | $ | 2,006 | | $ | 6 | $ | - | $ | 6 | FES | | 13 | | 1,103 | | - | | 1,116 | | | 5 | | - | | 5 | OE | | - | | 123 | | - | | 123 | | | - | | - | | - | TE | | - | | 75 | | - | | 75 | | | - | | - | | - | JCP&L | | 5 | | 276 | | - | | 281 | | | - | | - | | - | Met-Ed | | 9 | | 134 | | - | | 143 | | | - | | - | | - | Penelec | | 5 | | 185 | | - | | 190 | | | - | | - | | - | | | | | | | | | | | | | | | | | | | Level 3 - Assets | | | Level 3 - Liabilities | | | Derivatives | | Available-for- Sale Securities(1) | | NUG Contracts(2) | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | $ | - | $ | - | $ | 220 | $ | 220 | | $ | - | $ | 685 | $ | 685 | JCP&L | | - | | - | | 9 | | 9 | | | - | | 425 | | 425 | Met-Ed | | - | | - | | 187 | | 187 | | | - | | 152 | | 152 | Penelec | | - | | - | | 24 | | 24 | | | - | | 108 | | 108 |
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility | (1) | Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $2 million of receivables, payables and accrued income. |
(2) NUG contracts are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicablecompletely offset by regulatory assets and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of March 31, 2009:do not impact earnings.
Recurring Fair Value Measures as of December 31, 2008 | | Recurring Fair Value Measures as of December 31, 2008 | | | Revolving | | Regulatory and | | | Level 1 – Assets | | | Level 1 - Liabilities | | | Credit Facility | | Other Short-Term | | (In millions) | | | | | | | | | | (In millions) | | | Derivatives | | Available-for- Sale Securities(1) | | Other Investments | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | | $ | 2,750 | | $ | - | (1) | $ | - | $ | 537 | $ | - | $ | 537 | | $ | 25 | $ | - | $ | 25 | FES | | | 1,000 | | | - | (1) | | - | | 290 | | - | | 290 | | | 25 | | - | | 25 | OE | | | 500 | | | 500 | | | - | | 18 | | - | | 18 | | | - | | - | | - | Penn | | | 50 | | | 39 | (2) | | CEI | | | 250 | (3) | | 500 | | | JCP&L | | | - | | 67 | | - | | 67 | | | - | | - | | - | Met-Ed | | | - | | 104 | | - | | 104 | | | - | | - | | - | Penelec | | | - | | 58 | | - | | 58 | | | - | | - | | - | | | | | | | | | | | | | | | | | | | | | Level 2 - Assets | | | Level 2 - Liabilities | | | | Derivatives | | Available-for- Sale Securities(1) | | Other Investments | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | | $ | 40 | $ | 1,464 | $ | 83 | $ | 1,587 | | $ | 31 | $ | - | $ | 31 | FES | | | 12 | | 744 | | - | | 756 | | | 28 | | - | | 28 | OE | | | - | | 98 | | - | | 98 | | | - | | - | | - | TE | | | 250 | (3) | | 500 | | | - | | 73 | | - | | 73 | | | - | | - | | - | JCP&L | | | 425 | | | 428 | (2) | | 7 | | 255 | | - | | 262 | | | - | | - | | - | Met-Ed | | | 250 | | | 300 | (2) | | 14 | | 121 | | - | | 135 | | | - | | - | | - | Penelec | | | 250 | | | 300 | (2) | | 7 | | 174 | | - | | 181 | | | - | | - | | - | ATSI | | | - | (4) | | 50 | | | | | | | | | | | | | | | | | | | | | | | | | | (1)No regulatory approvals, statutory or charter limitations applicable. (2)Excluding amounts which may be borrowed under the regulated companies’ money pool. (3)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody’s. (4)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody’s or (ii) FirstEnergy has guaranteed ATSI’s obligations of such borrower under the facility. | | | | | Level 3 - Assets | | | Level 3 - Liabilities | | | | Derivatives | | Available-for- Sale Securities(1) | | NUG Contracts(2) | | Total | | | Derivatives | | NUG Contracts(2) | | Total | FirstEnergy | | $ | - | $ | - | $ | 434 | $ | 434 | | $ | - | $ | 766 | $ | 766 | JCP&L | | | - | | - | | 14 | | 14 | | | - | | 532 | | 532 | Met-Ed | | | - | | - | | 300 | | 300 | | | - | | 150 | | 150 | Penelec | | | - | | - | | 120 | | 120 | | | - | | 84 | | 84 |
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower’s borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of March 31, 2009, FirstEnergy’s and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower | | (1) | FirstEnergy(1)Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $5 million of receivables, payables
| | 60.8 | % | FES | | 57.3 | % | OE | | 44.8 | % | Penn | | 19.5 | % | CEI | | 54.4 | % | TE | | 44.6 | % | JCP&L | | 36.3 | % | Met-Ed | | 50.0 | % | Penelec | | 52.0 | %and accrued income. |
(1)(2) As of March 31, 2009, FirstEnergy could issue additional debt of approximately
$3.0 billion, or recognize a reduction in equity of approximately $1.6 billion,NUG contracts are completely offset by regulatory assets and
remain within the limitations of the financial covenants required by its revolving
credit facility. do not impact earnings.
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in “pricing grids”, whereby the cost of funds borrowed under the facility is related to the credit ratingsdetermination of the company borrowingabove fair value measures takes into consideration various factors. These factors include nonperformance risk, including counterparty credit risk and the funds.impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and nine months ended September 30, 2009 and 2008 (in millions):
| | FirstEnergy | | JCP&L | | Met-Ed | | Penelec | | Balance as of January 1, 2009 | | $ | (332 | ) | $ | (518 | ) | $ | 150 | | $ | 36 | | Settlements(1) | | | 273 | | | 132 | | | 63 | | | 78 | | Unrealized gains (losses)(1) | | | (406) | | | (30) | | | (178) | | | (198) | | Net transfers to (from) Level 3 | | | - | | | - | | | - | | | - | | Balance as of September 30, 2009 | | $ | (465) | | $ | (416) | | $ | 35 | | $ | (84) | | | | | | | | | | | | | | | | Change in unrealized gains (losses) relating to instruments held as of September 30, 2009 | | $ | (406) | | $ | (30) | | $ | (178) | | $ | (198) | | | | | | | | | | | | | | | | Balance as of July 1, 2009 | | $ | (536 | ) | $ | (466 | ) | $ | 23 | | $ | (93 | ) | Settlements(1) | | | 93 | | | 42 | | | 20 | | | 31 | | Unrealized gains (losses)(1) | | | (22) | | | 8 | | | (8) | | | (22) | | Net transfers to (from) Level 3 | | | - | | | - | | | - | | | - | | Balance as of September 30, 2009 | | $ | (465) | | $ | (416) | | $ | 35 | | $ | (84) | | | | | | | | | | | | | | | | Change in unrealized gains (losses) relating to instruments held as of September 30, 2009 | | $ | (22) | | $ | 8 | | $ | (8) | | $ | (22) | |
FirstEnergy Money Pools (1) Changes in fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings.
FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first three months of 2009 was 0.97% for the regulated companies’ money pool and 1.01% for the unregulated companies’ money pool.
Pollution Control Revenue Bonds
As of March 31, 2009, FirstEnergy’s currently payable long-term debt includes approximately $1.6 billion (FES - $1.6 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or; if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks:
| | Aggregate LOC | | | | Reimbursements of | LOC Bank | | Amount(4) | | LOC Termination Date | | LOC Draws Due | | | (In millions) | | | | | Barclays Bank | | $ | 149 | | June 2009 | | June 2009 | Bank of America(1) | | 101 | | June 2009 | | June 2009 | The Bank of Nova Scotia | | 255 | | Beginning June 2010 | | Shorter of 6 months or LOC termination date | The Royal Bank of Scotland | | 131 | | June 2012 | | 6 months | KeyBank(2) | | 266 | | June 2010 | | 6 months | Wachovia Bank | | 153 | | March 2014 | | March 2014 | Barclays Bank(3) | | 528 | | Beginning December 2010 | | 30 days | PNC Bank | | 70 | | Beginning December 2010 | | 180 days | Total | | $ | 1,653 | | | | | | | | | | | | (1) Supported by two participating banks, with each having 50% of the total commitment. (2) Supported by four participating banks, with the LOC bank having 62% of the total commitment. (3) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (4) Includes approximately $16 million of applicable interest coverage. |
In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. In addition, approximately $250 million of FirstEnergy’s PCRBs that are currently supported by LOCs are expected to be remarketed or refinanced in fixed interest rate modes and secured by FMBs, thereby eliminating or reducing the need for third-party credit support.
Long-Term Debt Capacity
As of March 31, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.7 billion of additional FMBs on the basis of property additions and retired bonds under the terms of their respective mortgage indentures. As a result of the issuance of senior secured notes by TE referred to below and related amendments to the TE mortgage indenture’s bonding ratio, that capacity decreased to $2.3 billion. 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, CEI and TE to incur additional secured debt not otherwise permitted by a specified exception of up to $171 million, $164 million and $117 million, respectively, as of March 31, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. Based upon FGCO’s FMB indenture, net earnings and available bondable property additions as of March 31, 2009, FGCO had the capability to issue $2.7 billion of additional FMBs under the terms of that indenture. Met-Ed and Penelec had the capability to issue secured debt of approximately $423 million and $321 million, respectively, under provisions of their senior note indentures as of March 31, 2009.
FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On March 2, 2009, Moody’s assigned a Baa1 senior secured rating to FES-related secured issuances. The following table displays FirstEnergy’s, FES’ and the Utilities’ securities ratings as of April 30 2009. S&P’s and Moody’s outlook for FirstEnergy and its subsidiaries remains “stable.”
| | | | | | | | | | | | | | FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | | | | | | | FES | | Senior secured | | BBB | | Baa1 | | | Senior unsecured | | BBB | | Baa2 | | | | | | | | OE | | Senior secured | | BBB+ | | Baa1 | | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Penn | | Senior secured | | A- | | Baa1 | | | | | | | | CEI | | Senior secured | | BBB+ | | Baa2 | | | Senior unsecured | | BBB | | Baa3 | | | | | | | | TE | | Senior secured | | BBB+ | | Baa2 | | | Senior unsecured | | BBB | | Baa3 | | | | | | | | JCP&L | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Met-Ed | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Penelec | | Senior unsecured | | BBB | | Baa2 |
On September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants have utilized, and may in the future utilize, the shelf registration statement to offer and sell unsecured, and in some cases, secured debt securities. | | FirstEnergy | | JCP&L | | Met-Ed | | Penelec | | Balance as of January 1, 2008 | | $ | (803 | ) | $ | (750 | ) | $ | (28 | ) | $ | (25 | ) | Settlements(1) | | | 167 | | | 152 | | | (5) | | | 20 | | Unrealized gains (losses)(1) | | | 314 | | | (43) | | | 236 | | | 121 | | Net transfers to (from) Level 3 | | | - | | | - | | | - | | | - | | Balance as of September 30, 2008 | | $ | (322) | | $ | (641) | | $ | 203 | | $ | 116 | | | | | | | | | | | | | | | | Change in unrealized gains (losses) relating to instruments held as of September 30, 2008 | | $ | 314 | | $ | (43) | | $ | 236 | | $ | 121 | | | | | | | | | | | | | | | | Balance as of July 1, 2008 | | $ | (17 | ) | $ | (644 | ) | $ | 350 | | $ | 278 | | Settlements(1) | | | 57 | | | 57 | | | (7) | | | 7 | | Unrealized gains (losses)(1) | | | (362) | | | (54) | | | (140) | | | (169) | | Net transfers to (from) Level 3 | | | - | | | - | | | - | | | - | | Balance as of September 30, 2008 | | $ | (322) | | $ | (641) | | $ | 203 | | $ | 116 | | | | | | | | | | | | | | | | Change in unrealized gains (losses) relating to instruments held as of September 30, 2008 | | $ | (362) | | $ | (54) | | $ | (140) | | $ | (169) | |
(1) Changes in Cash Positionfair value of NUG contracts are completely offset by regulatory assets and do not impact earnings.
5. DERIVATIVE INSTRUMENTS
FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, natural gas, coal and energy transmission. To manage the volatility relating to these exposures, FirstEnergy uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are included in other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item.
Interest Rate Derivatives
Under the revolving credit facility, FirstEnergy, and its subsidiaries, incur variable interest charges based on LIBOR. FirstEnergy currently holds swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and $100 million expire in January 2010. The swaps are accounted for as cash flow hedges. As of September 30, 2009, the fair value of outstanding swaps was $(2) million.
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 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. For the three months and nine months ended September 30, 2009, FirstEnergy terminated forward swaps with a notional value of $2.3 billion and $2.4 billion, respectively. FirstEnergy recognized losses of approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will be amortized to interest expense over the life of the hedged debt.
As of March 31,September 30, 2009 FirstEnergy had $399 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash2008, the fair value of outstanding interest rate derivatives was $(2) million and cash equivalents consist$(3) million, respectively. Interest rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The effects of unrestricted, highly liquid instruments with an original or remaining maturityinterest rate derivatives on the consolidated statements of income and comprehensive income during the three months or less. As of March 31,and nine months ended September 30, 2009 approximately $311 million of cash and cash equivalents represented temporary overnight deposits.
During the first quarter of 2009, FirstEnergy received $248 million of cash from dividends and equity repurchases from its subsidiaries and paid $168 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%.
Cash Flows From Operating Activities
FirstEnergy's consolidated net cash from operating activities is provided primarily by its energy delivery services and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $462 million in the first three months of 2009 compared to $359 million in the first three months of 2008 as summarized in the following table:
| | Three Months Ended | | | | March 31, | | | | 2009 | | 2008 | | | | (In millions) | | Net income | | $ | 115 | | $ | 277 | | Non-cash charges | | | 375 | | | 211 | | Working capital and other | | | (28 | ) | | (129 | ) | | | $ | 462 | | $ | 359 | |
were:
Net cash provided from operating activities increased by $103 million in the first three months of 2009 compared to the first three months of 2008 primarily due to a $164 million increase in non-cash charges and a $101 million increase from working capital and other changes, partially offset by a $162 million decrease in net income (see Results of Operations above). The increase in non-cash charges is primarily due to higher amortization of regulatory assets, including CEI’s $216 million regulatory asset impairment, and changes in accrued compensation and retirement benefits. The change in accrued compensation and retirement benefits resulted primarily from higher non-cash retirement benefit expenses recognized in the first quarter of 2009. The changes in working capital and other primarily resulted from a $52 million increase in the collection of receivables, lower net tax payments of $20 million and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.
Cash Flows From Financing Activities
In the first three months of 2009, cash provided from financing activities was $70 million compared to $224 million in the first three months of 2008. The decrease was primarily due to lower short-term borrowings, partially offset by long-term debt issuances in the first quarter of 2009. The following table summarizes security issuances and redemptions.
| | Three Months Ended | | | | March 31 | | Securities Issued or Redeemed | | 2009 | | 2008 | | | | (In millions) | | New issues | | | | | | Pollution control notes | | $ | 100 | | $ | - | | Unsecured notes | | | 600 | | | - | | | | $ | 700 | | $ | - | | | | | | | | | | Redemptions | | | | | | | | Pollution control notes(1) | | $ | 437 | | $ | 362 | | Senior secured notes | | | 7 | | | 6 | | | | $ | 444 | | $ | 368 | | | | | | | | | | Short-term borrowings, net | | $ | - | | $ | 746 | | | | | | | | | | (1) Includes the mandatory purchase of certain auction rate PCRBs described above. | |
On January 20, 2009, Met-Ed issued $300 million of 7.70% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings. On January 27, 2009, JCP&L issued $300 million of 7.35% Senior Notes due 2019 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes. On April 24, 2009, TE issued $300 million of 7.25% Senior Secured Notes due 2020 and used the net proceeds to repay short-term borrowings, to fund capital expenditures and for other general corporate purposes. Each of these issuances was sold off the shelf registration referenced above.
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted principally from property additions. Additions for the energy delivery services segment primarily include expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the three months ended March 31 2009, and 2008 by business segment:
Summary of Cash Flows | | Property | | | | | | | | Provided from (Used for) Investing Activities | | Additions | | Investments | | Other | | Total | | Sources (Uses) | | (In millions) | | | | | | | | | | | | Three Months Ended March 31, 2009 | | | | | | | | | | | | | | | | | | | | ) | | | | Competitive energy services | | | | | | | | | | ) | | | | | | | | | | | ) | | | | | | ) | Inter-segment reconciling items | | | | | | | ) | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended March 31, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Competitive energy services | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | Inter-segment reconciling items | | | | | | | ) | | | | | | | | | | | | | | | | | | | | |
Net cash | | | Three Months Ended | | Nine Months Ended | | | | | September 30 | | September 30 | | | | | 2009 | | 2008 | | 2009 | | 2008 | | | | | (In millions) | | Effective Portion | | | | | | | | | | | | | | | Loss Recognized in AOCL | | $ | (17) | | $ | (2) | | $ | (18) | | $ | (11) | | | Loss Reclassified from AOCL into Interest Expense | | | (26) | | | (4) | | | (37) | | | (11) | | Ineffective Portion | | | | | | | | | | | | | | | Loss Recognized in Interest Expense | | | - | | | - | | | - | | | (5) | |
Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $94 million ($57 million net of tax) as of September 30, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.
Commodity Derivatives
FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for investing activitiesrisk management purposes to hedge exposures when it makes economic sense to do so, including circumstances in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.
The following tables summarize the fair value of commodity derivatives in FirstEnergy’s Consolidated Balance Sheets:
Derivative Assets | | Derivative Liabilities | | | Fair Value | | | | Fair Value | | | September 30 | | December 31 | | | | September 30 | | December 31 | | | 2009 | | 2008 | | | | 2009 | | 2008 | Cash Flow Hedges | | (In millions) | | Cash Flow Hedges | | (In millions) | Electricity Forwards | | | | | | Electricity Forwards | | | | | | Current Assets | $ | 13 | $ | 11 | | | Current Liabilities | $ | 5 | $ | 27 | Natural Gas Futures | | | | | | Natural Gas Futures | | | | | | Current Assets | | - | | - | | | Current Liabilities | | 8 | | 4 | | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 1 | | 5 | Other | | | | | | Other | | | | | | Current Assets | | - | | - | | | Current Liabilities | 5 | | 12 | | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 2 | | 4 | | | $ | 13 | $ | 11 | | | $ | 21 | | 52 | | | | | | | | | | | | | | | | | | | | | Derivative Assets | | Derivative Liabilities | | | | Fair Value | | | | Fair Value | | | | September 30 2009 | | December 31 2008 | | | | September 30 2009 | | December 31 2008 | Economic Hedges | | (In millions) | | Economic Hedges | | (In millions) | NUG Contracts | | | | NUG Contracts | | | | Power Purchase | | | | | | | Power Purchase | | | | | | Contract Asset | $ | 220 | $ | 434 | | | Contract Liability | $ | 685 | $ | 766 | Other | | | | | | Other | | | | | | Current Assets | | - | | 1 | | | Current Liabilities | | - | | 1 | | Long-Term Deferred Charges | | 19 | | 28 | | | Noncurrent Liabilities | | - | | - | | | $ | 239 | $ | 463 | | | $ | 685 | $ | 767 | Total Commodity Derivatives | $ | 252 | $ | 474 | | Total Commodity Derivatives | $ | 706 | $ | 819 |
Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of September 30, 2009.
| Purchases | | Sales | | Net | | | Units | | | (In thousands) | | Electricity Forwards | | 156 | | | (2,913 | ) | | (2,757 | ) | | MWH | | Heating Oil Futures | | 5,880 | | | - | | | 5,880 | | | Gallons | | Natural Gas Futures | | 3,000 | | | (2,500 | ) | | 500 | | | mmBtu | |
The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months and nine months ended September 30, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:
Derivatives in Cash Flow Hedging Relationships | Electricity | | | Natural Gas | | | Heating Oil | | | | | | | | | Forwards | | | Futures | | | Futures | | | Total | | Three Months Ended September 30, 2009 | | (in millions) | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | 15 | | $ | (2 | ) | $ | - | | $ | 13 | | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | Purchased Power Expense | | 11 | | | - | | | - | | | 11 | | | Fuel Expense | | - | | | (4 | ) | | (2 | ) | | (6 | ) | | | | | | | | | | | | | | | Nine Months Ended September 30, 2009 | | | | | | | | | | | | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | 19 | | $ | (9 | ) | $ | - | | $ | 10 | | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | Purchased Power Expense | | (6 | ) | | - | | | - | | | (6 | ) | | Fuel Expense | | - | | | (9 | ) | | (10 | ) | | (19 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, 2008 | | | | | | | | | | | | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | 42 | | $ | (2 | ) | $ | - | | $ | 40 | | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | Purchased Power Expense | | 3 | | | - | | | - | | | 3 | | | Fuel Expense | | - | | | 3 | | | - | | | 3 | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2008 | | | | | | | | | | | | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | 12 | | $ | 4 | | $ | - | | $ | 16 | | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | | Purchased Power Expense | | (10 | ) | | - | | | - | | | (10 | ) | | Fuel Expense | | - | | | 4 | | | - | | | 4 | | | | | | | | | | | | | | | | (1) The ineffective portion was immaterial. | | | | | | | | | | | | |
| | Three Months Ended September 30 | | | Nine Months Ended September 30 | | Derivatives Not in Hedging Relationships | | | NUG | | | | | | | | | | NUG | | | | | | | | | | | Contracts | | | Other | | | Total | | | | Contracts | | | Other | | | Total | | 2009 | | (In millions) | | Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | | Fuel Expense(1) | | $ | - | | $ | (1 | ) | $ | (1 | ) | | $ | - | | $ | 2 | | $ | 2 | | Regulatory Assets(2) | | | (22 | ) | | - | | | (22 | ) | | | (406 | ) | | - | | | (406 | ) | | | $ | (22 | ) | $ | (1 | ) | $ | (23 | ) | | $ | (406 | ) | $ | 2 | | $ | (404 | ) | Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | | Fuel Expense(1) | | $ | - | | $ | 1 | | $ | 1 | | | $ | - | | $ | - | | $ | - | | Regulatory Assets(2) | | | (93 | ) | | - | | | (93 | ) | | | (273 | ) | | 11 | | | (262 | ) | | | $ | (93 | ) | $ | 1 | | $ | (92 | ) | | $ | (273 | ) | $ | 11 | | $ | (262 | ) | 2008 | | | | | | | | | | | | | | | | | | | | | Unrealized Gain (Loss) Recognized in: | | | | | | | | | | | | | | | | | | | | | Fuel Expense(1) | | $ | - | | $ | 2 | | $ | 2 | | | $ | - | | $ | 2 | | $ | 2 | | Regulatory Assets(2) | | | (362 | ) | | 1 | | | (361 | ) | | | 314 | | | 1 | | | 315 | | | | $ | (362 | ) | $ | 3 | | $ | (359 | ) | | $ | 314 | | $ | 3 | | $ | 317 | | Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | | | | | | | | | | Fuel Expense(1) | | $ | - | | $ | 1 | | $ | 1 | | | $ | - | | $ | 1 | | $ | 1 | | Regulatory Assets(2) | | | (57 | ) | | 1 | | | (56 | ) | | | (167 | ) | | 11 | | | (156 | ) | | | $ | (57 | ) | $ | 2 | | $ | (55 | ) | | $ | (167 | ) | $ | 12 | | $ | (155 | ) | | | | (1) The realized gain (loss) is reclassified upon termination of the derivative instrument. | | (2) Changes in the fair value of NUG contracts are deferred for future recovery from (or refund to) customers. | |
Total unamortized losses included in AOCL associated with commodity derivatives were $9 million ($5 million net of tax) as of September 30, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a net $7 million decrease related to current hedging activity and a $15 million decrease due to net hedge losses reclassified to earnings during the first nine months of 2009. Based on current estimates, approximately $3 million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.
Many of FirstEnergy’s commodity derivatives contain credit risk features. As of September 30, 2009, FirstEnergy posted $133 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on September 30, 2009 was $2 million, for which $106 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $18 million of additional collateral related to commodity derivatives.
6. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31. FirstEnergy also 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 available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
On June 2, 2009, FirstEnergy amended its health care benefits plan (Plan) for all employees and retirees eligible to participate in the Plan. The Plan amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. As a result of the remeasurement, the Plan’s discount rate was revised to 7.5% while the expected long-term rate of return on assets remained at 9%. The remeasurement and Plan amendment increased FirstEnergy’s AOCI by approximately $449 million ($252 million, net of tax) in the second quarter of 2009 and reduced FirstEnergy’s 2009 net postretirement benefit cost (including amounts capitalized) by $48 million, including $27 million applicable to the first nine months of 2009.
In the third quarter of 2009, FirstEnergy incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees. The special termination benefits of the VERO included additional health care coverage subsidies paid by FirstEnergy to those qualified employees who elected to retire. A total of 715 employees accepted the VERO.
On September 2, 2009, the Utilities and ATSI made a $500 million voluntary contribution to the FirstEnergy Corp. Pension Plan (Pension Plan). Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure its Pension Plan as of August 31, 2009. As a result of the remeasurement, the Pension Plan’s discount rate was revised to 6% while the expected long-term rate of return on assets remained at 9%. The remeasurement and voluntary contribution decreased FirstEnergy’s AOCI by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million, including a $2 million reduction that is applicable to the third quarter of 2009.
FirstEnergy’s net pension and OPEB expenses (benefits) for the three months ended September 30, 2009 and 2008 were $36 million (including $9 million attributable to the VERO-related charge mentioned above), and $(15) million, respectively. For the nine months ended September 30, 2009 and 2008, FirstEnergy’s net pension and OPEB expenses (benefits) were $117 million and $(44) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit costs (including amounts capitalized) for the three months and nine months ended September 30, 2009 and 2008, consisted of the following:
| | Three Months Ended | | Nine Months Ended | | | | September 30 | | September 30 | | Pension Benefits | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | Service cost | | $ | 23 | | $ | 22 | | $ | 66 | | $ | 65 | | Interest cost | | | 79 | | | 75 | | | 239 | | | 224 | | Expected return on plan assets | | | (86 | ) | | (116 | ) | | (248 | ) | | (347 | ) | Amortization of prior service cost | | | 3 | | | 3 | | | 10 | | | 10 | | Recognized net actuarial loss | | | 45 | | | 2 | | | 129 | | | 6 | | Net periodic cost (credit) | | $ | 64 | | $ | (14 | ) | $ | 196 | | $ | (42 | ) |
| | Three Months Ended | | Nine Months Ended | | | | September 30 | | September 30 | | Other Postretirement Benefits | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | Service cost | | $ | 15 | | $ | 5 | | $ | 23 | | $ | 14 | | Interest cost | | | 13 | | | 18 | | | 51 | | | 55 | | Expected return on plan assets | | | (9 | ) | | (13 | ) | | (27 | ) | | (38 | ) | Amortization of prior service cost | | | (48 | ) | | (37 | ) | | (127 | ) | | (111 | ) | Recognized net actuarial loss | | | 15 | | | 12 | | | 46 | | | 35 | | Net periodic cost (credit) | | $ | (14 | ) | $ | (15 | ) | $ | (34 | ) | $ | (45 | ) |
Pension and postretirement benefit obligations are allocated to FirstEnergy's subsidiaries employing the plan participants. FES and the Utilities capitalize employee benefits related to construction projects. The net periodic pension costs and net periodic postretirement benefit costs (including amounts capitalized) recognized by FES and each of the Utilities for the three months and nine months ended September 30, 2009 and 2008 were as follows:
| | Three Months Ended | | Nine Months Ended | | | | September 30 | | September 30 | | Pension Benefit Cost (Credit) | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | FES | | $ | 19 | | $ | 5 | | $ | 56 | | $ | 16 | | OE | | | 6 | | | (6 | ) | | 20 | | | (18 | ) | CEI | | | 5 | | | (1 | ) | | 14 | | | (3 | ) | TE | | | 2 | | | (1 | ) | | 5 | | | (2 | ) | JCP&L | | | 8 | | | (3 | ) | | 26 | | | (10 | ) | Met-Ed | | | 5 | | | (2 | ) | | 16 | | | (7 | ) | Penelec | | | 4 | | | (3 | ) | | 13 | | | (9 | ) | Other FirstEnergy subsidiaries | | | 15 | | | (3 | ) | | 46 | | | (9 | ) | | | $ | 64 | | $ | (14 | ) | $ | 196 | | $ | (42 | ) |
| | Three Months Ended | | Nine Months Ended | | | | September 30 | | September 30 | | Other Postretirement Benefit Cost (Credit) | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | FES | | $ | (4 | ) | $ | (2 | ) | $ | (8 | ) | $ | (5 | ) | OE | | | (3 | ) | | (2 | ) | | (8 | ) | | (5 | ) | CEI | | | - | | | 1 | | | 1 | | | 2 | | TE | | | 1 | | | 1 | | | 2 | | | 3 | | JCP&L | | | (2 | ) | | (4 | ) | | (4 | ) | | (12 | ) | Met-Ed | | | (1 | ) | | (3 | ) | | (3 | ) | | (8 | ) | Penelec | | | (1 | ) | | (3 | ) | | (2 | ) | | (10 | ) | Other FirstEnergy subsidiaries | | | (4 | ) | | (3 | ) | | (12 | ) | | (10 | ) | | | $ | (14 | ) | $ | (15 | ) | $ | (34 | ) | $ | (45 | ) |
7. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary. FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the consolidated balance sheets is the result of net losses of the noncontrolling interests ($14 million), the acquisition of additional interest in certain joint ventures ($13 million), and distributions to owners ($4 million).
Mining Operations
On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective August 21, 2009, the joint venture acquired the remaining 20% stake in the mining operations by issuing a five-year note for $47.5 million. FEV consolidates the mining and transportation operations of this joint venture in its financial statements.
Trusts
FirstEnergy's consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
Loss Contingencies
FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company's net exposure to loss based upon the casualty value provisions mentioned above:
| | Maximum Exposure | | Discounted Lease Payments, net(1) | | Net Exposure | | | (In millions) | FES | | $ | 1,371 | | $ | 1,193 | | $ | 178 | OE | | 729 | | 561 | | 168 | CEI(2) | | 670 | | 74 | | 596 | TE(2) | | 670 | | 383 | | 287 |
| (1) | The net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments is $1.7 billion |
| (2) | CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements. |
In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI's and TE's obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO's leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.
Power Purchase Agreements
FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 25 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of consolidation consideration for VIEs. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs from those contracts to be recovered from customers. Purchased power costs from these entities during the three months and nine months ended September 30, 2009 and 2008 are shown in the following table:
| | Three Months Ended | | Nine Months Ended | | | | September 30 | | September 30 | | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | JCP&L | | $ | 20 | | $ | 26 | | $ | 57 | | $ | 67 | | Met-Ed | | | 11 | | | 12 | | | 39 | | | 44 | | Penelec | | | 9 | | | 8 | | | 26 | | | 25 | | Total | | $ | 40 | | $ | 46 | | $ | 122 | | $ | 136 | |
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L's supply of BGS.
JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of September 30, 2009, $349 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II, and are collateralized by each company's equity and assets, which consists primarily of bondable transition property.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.
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. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, increased by $36FirstEnergy recognized $13 million comparedin tax benefits, which favorably affected FirstEnergy's effective tax rate. Material changes to FirstEnergy's unrecognized tax benefits during the firstthird quarter of 2008. The increase was primarily due2009 are described further below. Upon completion of the federal tax examinations for tax years 2004 to the absence in 2009 of cash proceeds from the sale of telecommunication assets2006 in the firstthird quarter of 2008, FirstEnergy recognized approximately $45 million in tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate. A majority of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and higher cash investmentsaccumulated deferred income taxes for temporary tax items ($15 million). As of September 30, 2009, FirstEnergy expects that $197 million of unrecognized benefits will be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy's effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.
The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The reversal of accrued interest associated with the $45 million in recognized tax benefits in 2008 favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008. During the first nine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of September 30, 2009 was $67million, as compared to $59 million as of December 31, 2008.
In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved the change in accounting method and $281 million of costs were included as a repair deduction in FirstEnergy’s 2008 consolidated tax return. Since the IRS did not complete its review over this change in accounting method by the extended filing date of FirstEnergy’s federal tax return, FirstEnergy increased the amount of unrecognized tax benefits by $34 million in the third quarter of 2009, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item. There was no impact on FirstEnergy’s effective tax rate for the Signal Peak mining operationsquarter.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in 2009, partially offset by lower property additions. Property additions decreased as a result of lower AQC system expendituresJuly 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the absenceyear 2009 in February 2009 of acquisition costs for the Fremont Plant in the first quarter of 2008.
During the remaining three quarters of 2009, capital requirements for property additions and capital leases are expected to be approximately $1.4 billion, including approximately $225 million for nuclear fuel. FirstEnergy has additional requirements of approximately $316 million for maturing long-term debt during the remainder of 2009, of which $100 million was redeemed in April 2009. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.
FirstEnergy's capital spending for the period 2009-2013under its Compliance Assurance Process program. Neither audit is expected to be approximately $8.1 billion (excluding nuclear fuel),close before December 2009. Management believes that adequate reserves have been recognized and final settlement of which approximately $1.6 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $338 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments arethese audits is not expected to be reduced by approximately $1.0 billion and $136 million, respectively, as the nuclear fuel is consumed.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. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.
As of March 31,September 30, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.5aggregated approximately $4.1 billion, as summarized below:
| | Maximum | | Guarantees and Other Assurances | | | | | | (In millions) | | FirstEnergy Guarantees on Behalf of its Subsidiaries | | | | Energy and Energy-Related Contracts (1) | | $ | 433 | | LOC (long-term debt) – interest coverage (2) | | | 6 | | Other (3) | | | 742 | | | | | 1,181 | | | | | | | Subsidiaries’ Guarantees | | | | | Energy and Energy-Related Contracts | | | 77 | | LOC (long-term debt) – interest coverage (2) | | | 9 | | FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,552 | | | | | 2,638 | | | | | | | Surety Bonds | | | 111 | | LOC (long-term debt) – interest coverage (2) | | | 2 | | LOC (non-debt) (4)(5) | | | 570 | | | | | 683 | | Total Guarantees and Other Assurances | | $ | 4,502 | |
| (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 $1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets. |
| (3) | Includes guarantees of $300 million for OVEC obligations and $80 million for nuclear decommissioning funding assurances. Also includes $300 million for a Credit Suisse credit facility for FGCO that is guaranteed by both FirstEnergy and FES. |
| (4) | Includes $145 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility. |
| (5) | Includes approximately $291 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry Unit 1 by OE. A $236 million LOC relating to the sale-leaseback of Beaver Valley Unit 2 by OE expires in May 2009 and is expected to be replaced by a $161 million LOC. |
consisting primarily of parental guarantees ($1 billion), subsidiaries’ guarantees ($2.6 billion), surety bonds ($0.1 billion) 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 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 financingsfinancing 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’sFirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes theThe likelihood is remote that such parental guarantees willof $0.4 billion (included in the $1 billion shown above) as of September 30, 2009 would increase amounts otherwise paidpayable 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 to below investment grade 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 March 31,September 30, 2009, FirstEnergy’sFirstEnergy's maximum exposure under these collateral provisions was $761$616 million, as shown below:
Collateral Provisions | | FES | | Utilities | | Total | | | | (In millions) | | Credit rating downgrade to below investment grade | | $ | 315 | | $ | 170 | | $ | 485 | | Acceleration of payment or funding obligation | | | 80 | | | 141 | | | 221 | | Material adverse event | | | 50 | | | 5 | | | 55 | | Total | | $ | 445 | | $ | 316 | | $ | 761 | |
Stressconsisting of $53 million due to “material adverse event” contractual clauses and $563 million due to a below investment grade credit rating. 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 the total potentialthis amount to $830$699 million, consisting of $54$60 million due to “material adverse event” contractual clauses and $776$639 million due to a below investment grade credit rating.
Most of FirstEnergy’sFirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $103 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfoliocontracts as of March 31,September 30, 2009, and forward prices as of that date, FES had $205$183 million of outstanding collateral payments.payments of which $134 million is included in other assets on the Consolidated Balance Sheet as of September 30, 2009. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices)prices thereafter), FES would be required to post an additional $77$45 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.
OFF-BALANCE SHEET ARRANGEMENTS
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Ohio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in the amount of approximately $500 million. The surplus margin guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 13). 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.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have obligationsclaims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
(B) ENVIRONMENTAL MATTERS
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not included on their Consolidated Balance Sheets relatedsubject to salesuch regulations and, leaseback arrangements involvingtherefore, do not bear the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present valuerisk of these sale and leaseback operating lease commitments, netcosts associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of trust investments is $1.7 billion as of March 31, 2009.approximately $800 million for the period 2009-2013.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has equity ownership interestsan obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in certain businessesFirstEnergy’s determination of environmental liabilities and are accrued in the period that are accounted for using the equity method of accounting for investments. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under “Guaranteesthey become both probable and Other Assurances” above.reasonably estimable. Clean Air Act Compliance
MARKET RISK INFORMATION
FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarilyis required to managemeet federally-approved SO2 emissions regulations. Violations of such regulations can result in the riskshutdown of price and interest rate fluctuations. FirstEnergy's Risk Policy Committee, comprisedthe generating unit involved and/or civil or criminal penalties of members of senior management, provides general oversightup to $37,500 for risk management activities throughouteach day the company.unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
Commodity Price RiskFirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
FirstEnergy is exposedIn 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to financialas the NSR cases. OE’s and market risks resulting fromPenn’s settlement with the fluctuation of interest ratesEPA, the DOJ and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuelthree states (Connecticut, New Jersey and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. DerivativesNew York) that fall within the scope of SFAS 133 must be recorded at their fair value and marked to market. The majority of FirstEnergy’s derivative hedging contracts qualify for the normal purchase and normal sale exception under SFAS 133 and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuantresolved all issues related to the Public Utility Regulatory Policies ActSammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of 1978. These non-trading contracts are adjusted to fair valuea consent decree, requires reductions of NOX and SO2 emissions at the endSammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of each quarter,pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with a corresponding regulatory asset recognizedthat agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for above-market costs or regulatory liabilitybiomass fuel consumption, are currently estimated to be $706 million for below-market costs. The change2009-2012 (with $414 million expected to be spent in the fair value of commodity derivative contracts related to energy production during the first quarter of 2009 is summarized in the following table:2009).
Fair Value of Commodity Derivative Contracts | | Non-Hedge | | Hedge | | Total | | | (In millions) | Change in the Fair Value of | | | | | | | Commodity Derivative Contracts: | | | | | | | Outstanding net liability as of January 1, 2009 | $ | (304 | ) | $ | (41 | ) | $ | (345 | ) | Additions/change in value of existing contracts | | (227 | ) | | (10 | ) | | (237 | ) | Settled contracts | | 74 | | | 22 | | | 96 | | Outstanding net liability as of March 31, 2009 (1) | $ | (457 | ) | $ | (29 | ) | $ | (486 | ) | | | | | | | | | | | Non-commodity Net Liabilities as of March 31, 2009: | | | | | | | | | | Interest rate swaps (2) | | - | | | (4 | ) | | (4 | ) | Net Liabilities - Derivative Contracts as of March 31, 2009 | $ | (457 | ) | $ | (33 | ) | $ | (490 | ) | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | Income Statement effects (pre-tax) | $ | 1 | | $ | - | | $ | 1 | | Balance Sheet effects: | | | | | | | | | | Other comprehensive income (pre-tax) | $ | - | | $ | 12 | | $ | 12 | | Regulatory assets (net) | $ | 154 | | $ | - | | $ | 154 | | | | | | | | | | | | (1) Includes $457 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. (2) Interest rate swaps are treated as cash flow or fair value hedges. (3) Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions. | |
DerivativesOn May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a settlement of the PennFuture complaint was reached with PennFuture and one of the three individual complainants. On October 16, 2009, the Court approved the settlement and dismissed the claims of PennFuture and of the settling individual complainant. The other two non-settling complainants are included onnow represented by counsel handling the Consolidated Balance Sheet asthree cases filed in July 2008. FGCO believes those claims are without merit and intends to defend itself against the allegations made in those three complaints. The Pennsylvania Department of Health, under a Cooperative Agreement with the Agency for Toxic Substances and Disease Registry, completed a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other non-current liabilities | | | | ) | | | | | | | | | | | | | | | | | | | | | | ) | | | | | | ) |
which concluded there is insufficient sampling data to determine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The 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 electricityreport recommended additional air monitoring 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 4 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of March 31, 2009 are summarized by yearsample analysis in the following table:vicinity of the Mansfield Plant, which the Pennsylvania Department of Environmental Protection has completed.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. 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 on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.
On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter. On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”), and Title V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. On September 15, 2009, FGCO received an additional information request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 15, 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter. On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
In March 2005, the EPA finalized CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX 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. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA opened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose maximum achievable control technology (MACT) regulations for mercury and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. FGCO’s future cost of compliance with MACT regulations may be substantial and will depend on the action taken by the EPA and on how any future regulations are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. The EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, increasing to 25% by 2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the House of Representatives passed one such bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources. On September 23, 2009, the EPA finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when Clean Air Act permits under the New Source Review and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.
Source of Information | | | | | | | | | | | | | | | | - Fair Value by Contract Year | | | | | | | | | | | | | | | | | | (In millions) | | Prices actively quoted(2) | | $ | (17 | ) | $ | (13 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | (30 | ) | Other external sources(3) | | | (296 | ) | | (241 | ) | | (195 | ) | | (107 | ) | | - | | | - | | | (839 | ) | Prices based on models | | | | | | | | | | | | | | | | | | | | | | | Total(4) | | | | ) | | | ) | | | ) | | | ) | | | | | | | | | ) |
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. 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. (1)Connecticut v. AEP, No. 05-5105-cv (2d Cir. 2009)(seeking injunctive relief only); Comer v. Murphy Oil USA, No. 07-6-756 (5th ForCir. 2009)(seeking damages only), respectively. While FirstEnergy is not a party to either litigation, should the last three quarterscourts of 2009. (2) Represents exchange traded NYMEX futures and options.
(3) Primarily represents contracts based on broker and ICE quotes.
| (4) | Includes $457 million in non-hedge commodity derivative contracts (primarily with NUGs), which are offset by a regulatory asset. |
appeals decisions be affirmed, FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase and/or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of March 31, 2009. Based on derivative contracts held as of March 31, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $1 million during the next 12 months.
Forward Starting Swap Agreements - Cash Flow Hedges
FirstEnergy utilizes forward starting swap agreements in order to hedge a portion of the consolidated interest rate risk associated with anticipated future issuances of fixed-rate, long-term debt securities for one or more of its consolidated subsidiaries could be named in 2009actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and 2010,other expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and anticipated variable-rate, short-term debt. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury and LIBOR rates between the date of hedge inception and the date of the debt issuance. During the first three months of 2009, FirstEnergy terminated forward swaps with an aggregate notional value of $100 million. FirstEnergy paid $1.3 million in cash related to the terminations, $0.3 million of which was deemed ineffective and recognized in current period earnings. The remaining effective portion ($1.0 million) will be recognized over the terms of the associated future debt. As of March 31, 2009, FirstEnergy had outstanding forward swaps with an aggregate notional amount of $200 million and an aggregate fair value of $(4) million.nuclear generators.
| | March 31, 2009 | | December 31, 2008 | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | (In millions) | | Cash flow hedges | | $ | | | | | | $ | | | | | | | | | $ | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, 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 large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’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. EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter. Regulation of Waste Disposal
Equity Price RiskAs a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. The EPA is reviewing its previous determination that Federal regulation of coal ash as a hazardous waste is not appropriate. The EPA has indicated an intent to propose regulations regarding this issue by the end of the year. Additional regulations of fossil-fuel combustion waste products could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the states.
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits, which include certain employee contributions, deductibles, and co-payments, upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. Reductions in plan assets from investment losses during 2008 resulted in a decrease to the plans’ funded status of $1.7 billion and an after-tax decrease to common stockholders’ equity of $1.2 billion. As of December 31, 2008, the pension plan was underfunded and FirstEnergy currently estimates that additional cash contributions will be required in 2011 for the 2010 plan year. The overall actual investment result during 2008 was a loss of 23.8% compared to an assumed 9% positive return. Based on an assumed 7% discount rate, FirstEnergy’s pre-tax net periodic pension and OPEB expense was $43 million in the first quarter of 2009.
Nuclear decommissioning trust fundsThe Utilities have been establishednamed 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 satisfy NGC’sdispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and our Utilities’ nuclear decommissioning obligations. Asseveral basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of March 31,September 30, 2009, approximately 31%based on estimates of the funds were invested in equity securitiestotal costs of cleanup, the Utilities' proportionate responsibility for such costs and 69% were invested in fixed income securities, with limitations relatedthe financial ability of other unaffiliated entities to concentration and investment grade ratings. The equity securities are carried at their market valuepay. Total liabilities of approximately $507$104 million as(JCP&L - - $77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through September 30, 2009. Included in the total are accrued liabilities of March 31, 2009. A hypothetical 10% decreaseapproximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in prices quotedNew Jersey, which are being recovered by stock exchanges would resultJCP&L through a non-bypassable SBC. (C) OTHER LEGAL PROCEEDINGS
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. Two class action lawsuits (subsequently consolidated into a $51 million reductionsingle proceeding) were filed in fair value asNew 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 March 31, 2009.contract causes of actions. The decommissioning trustsclass was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments heldtransformers in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trustsRed Bank, NJ, based on a common incident involving the guidance for other-than-temporary impairments providedfailure of the bushings of two large transformers in SFAS 115, FSP SFAS 115-1the Red Bank substation which resulted in planned and SFAS 124-1. Onunplanned outages in the area during a 2-3 day period, and (2) in March 27, 2009, FENOC submitted2007, the Appellate Division remanded this matter back to the NRCTrial Court to allow plaintiffs sufficient time to establish a biennial evaluationdamage model or individual proof of the funding status of these trusts and concluded that the amounts in the trusts as of December 31, 2008, when coupled with the rates of return allowable by the NRC (over a safe store period for certain units) and the existing parental guarantee, would provide reasonable assurance of funding for decommissioning cost estimates under current NRC regulations. FirstEnergy does not expect to make additional cash contributions to the nuclear decommissioning trusts in 2009, other than the required annual TMI-2 trust contribution that is collected through customer rates. However, should the trust funds continue to experience declines in market value, FirstEnergy may be required to take measures, such as providing financial guarantees through LOCs or parental guarantees or making additional contributions to the trusts to ensure that the trusts are adequately funded and meet minimum NRC funding requirements.
CREDIT RISK
Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. FirstEnergy engages in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB+ (S&P). As ofdamages. On March 31, 2009, the largest credit concentrationtrial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed a motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was with JP Morgan, which is currently rated investment grade, representing 9.6%granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of FirstEnergy’s total approved credit risk.
OUTLOOKtheir appeal of the trial court's decision decertifying the class. The Appellate Division has scheduled oral argument for January 5, 2010..
State RegulatoryNuclear Plant Matters
In Ohio, New JerseyAugust 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and Pennsylvania, laws applicable2) for an additional 20 years. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities was extended until 2036 and 2047 for Units 1 and 2, respectively.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to electric industry restructuring contain similar provisionsdecommission its nuclear facilities. As of September 30, 2009, FirstEnergy had approximately $1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry, and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that are reflectedit planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the Utilities' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities; | | | · | establishing or defining the PLR obligations to customers in the Utilities' service areas; | | | · | providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; | | | · | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; | | | · | continuing regulation of the Utilities' transmission and distribution systems; and | | | · | requiring corporate separation of regulated and unregulated business activities. |
The Utilitiescapital markets and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUCits effects on particular businesses and the NJBPU have authorizedeconomy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for recoveryBeaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from customersFirstEnergy and maintaining the plant in future periodsa safe-store configuration, or extended safe shutdown condition, after plant shutdown. On October 20, 2009, FENOC received a request for which authorizationadditional information (RAI) from the NRC that questions FENOC's methodology for calculating the decommissioning obligations for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $130 million as of March 31, 2009 (JCP&L - $54 million and Met-Ed - $76 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for JCP&L and by 2020 for Met-Ed. The following table discloses regulatory assets by company:decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below. | | March 31, | | December 31, | | Increase | | Regulatory Assets* | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | OE | | $ | 545 | | $ | 575 | | $ | (30 | ) | CEI | | | 618 | | | 784 | | | (166 | ) | TE | | | 96 | | | 109 | | | (13 | ) | JCP&L | | | 1,162 | | | 1,228 | | | (66 | ) | Met-Ed | | | 490 | | | 413 | | | 77 | | ATSI | | | | | | | | | | ) | Total | | | | | | | | | | ) |
*
| Penelec had net regulatory liabilities of approximately $49 million
and $137 million as of March 31, 2009 and December 31, 2008,
respectively. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets.
| JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. The parties are participating in the federal court's mediation programs and have held private settlement discussions. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.
Regulatory assets by source are as follows:The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009, and a voluntary retirement program was implemented on August 19, 2009. A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.
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. | | March 31, | | December 31, | | Increase | | Regulatory Assets By Source | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Regulatory transition costs | | $ | 1,437 | | $ | 1,452 | | $ | (15 | ) | Customer shopping incentives | | | 211 | | | 420 | | | (209 | ) | Customer receivables for future income taxes | | | 220 | | | 245 | | | (25 | ) | Loss on reacquired debt | | | 50 | | | 51 | | | (1 | ) | Employee postretirement benefits | | | 29 | | | 31 | | | (2 | ) | Nuclear decommissioning, decontamination | | | | | | | | | | | and spent fuel disposal costs | | | (56 | ) | | (57 | ) | | 1 | | Asset removal costs | | | (225 | ) | | (215 | ) | | (10 | ) | MISO/PJM transmission costs | | | 342 | | | 389 | | | (47 | ) | Purchased power costs | | | 305 | | | 214 | | | 91 | | Distribution costs | | | 478 | | | 475 | | | 3 | | Other | | | | | | | | | | | Total | | | | | | | | | | ) |
10. REGULATORY MATTERS
Reliability Initiatives(A) RELIABILITY INITIATIVES
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requiresrequired JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC willmay take upon receipt of JCP&L’s response to NERC’sbased on the data request.submittals or interview results.
OhioOn June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.
(B) OHIO
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009.2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter.matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh.KWH. The power supply obtained through this process providesprovided generation service to the Ohio Companies’ retail customers who choosechose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OEdenied OE’s and TETE’s request to continue collecting RTC orand denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery ofrecovered the increased purchased power costs for OE and TE, and authorizes CEI to collectrecovered a portion of those costs currently and deferfor CEI, with the remainder being deferred for future recovery.
On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP providesprovided that generation willwould be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices willwould be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further providesprovided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI willwould agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies willwould collect a delivery service improvement rider at an overall average rate of $.002 per kWhKWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressesaddressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation taketook effect on April 1, 2009 while the remaining provisions taketook effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.
On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers.
The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.
SB221 also requires electric distribution utilities to implement energy efficiency programs thatprograms. Under the provisions of SB221, the Ohio Companies are required to achieve ana total annual energy savings equivalent of 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 2013.2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by one percent,1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. CostsThe PUCO may amend these benchmarks in certain, limited circumstances. Additionally, 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 serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance arewill be recoverable from customers.
PennsylvaniaOn June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised.
On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.
In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011.
On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2020. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP
(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenorsinterveners filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded andconcluded. On August 11, 2009, the companies are awaitingALJ issued a Recommended Decision fromto the ALJ.PPUC approving Met-Ed’s and Penelec’s TSCs as filed and dismissing all complaints. Exceptions by various interveners were filed and reply exceptions were filed by Met-Ed and Penelec. The TSCs includeCompanies are now awaiting a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.decision.
On April 15,May 28, 2009, Met-Edthe PPUC approved Met-Ed’s and Penelec filed revised TSCs with the PPUCPenelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC would resultresulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increaseincreased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposingthe PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs intoto a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The billAct 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart metersmeters; and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.
Major provisions of the legislation include:
· | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases; |
· | the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; |
· | utilities must provide for the installation of smart meter technology within 15 years; |
· | utilities must reduce peak demand by a minimum reduction in peak demand of 4.5% by May 31, 2013; |
· | minimum reductions inutilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and |
· | an expandedthe definition of alternative energyAlternative Energy was expanded to include additional types of hydroelectric and biomass facilities. |
Act 129 requires utilities to file with the PPUC, an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved, in part, and rejected, in part, the Pennsylvania Companies' filing. The Companies must file revised EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.
Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year.
Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requestedanticipate PPUC approval of their plan byin November 2009.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filingfiling to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51$59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The PPUC must actCompanies filed reply comments on this filing within 120 days.October 26, 2009, and await the decision of the PPUC.
New Jersey(D) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31,September 30, 2009, the accumulated deferred cost balance totaled approximately $165$102 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Following public hearing and consideration of comments from interested parties, the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or JCP&L.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.
The EMP was issued on October 22, 2008, establishing five major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. Such utility specific plans are due to be filed with the BPU by July 1, 2010. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.their operations.
In support of the New Jersey Governor’sGovernor's Economic Assistance and Recovery Plan, JCP&L announced its intenta proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. AnUnder the proposal, an estimated $40 million willwould be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. ApproximatelyIn addition, approximately $34 million willwould be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million willwould be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million willwould be spent on energy efficiency programs that willwould complement those currently being offered. CompletionThe project relating to expansion of the existing demand response programs was approved by the BPU on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.the proposal.
(E) FERC MattersMATTERS
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, FirstEnergy and Exelon filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.
PJM Transmission Rate
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design;design, notably AEP, which proposed to create a "postage stamp",stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. ThisAEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order ("Opinion 494") finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral argument wasarguments were held on April 13, 2009, and2009. The Seventh Circuit Court of Appeals issued a decision is expected this summer.on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion Electric Cooperative was denied by the Seventh Circuit on October 20, 2009. On October 28, 2009, the Seventh Circuit closed its case dockets and returned the case to FERC for further action on the remand order.
The FERC’s orders on PJM rate design will preventprevented the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reducereduces the costscost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Opinion 494 appeal discussed above. Now that the Seventh Circuit has ruled on the Opinion 494 case, AEP and FERC have until November 11, 2009, to advise the Seventh Circuit of any changes to their litigation positions that result from or reflect the Seventh Circuit’s decision in the Opinion 494 case.
Duquesne’s Request to Withdraw from PJMRTO Consolidation
On November 8, 2007, Duquesne Light Company (Duquesne)August 17, 2009, FirstEnergy filed a requestan application with the FERC requesting to exitconsolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and to join MISO. Duquesne’s proposed moveThe consolidation would affect numerous FirstEnergy interests, including but not limited tomake the terms under whichtransmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s Beaver Valley Plant would continue to participatetransmission assets in PJM’s energy markets. FirstEnergy, therefore, intervenedPennsylvania and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.transmission assets in New Jersey already operate as a part of PJM.
In November, 2008, DuquesneTo ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.
FirstEnergy has requested that FERC rule on its application and otherthe related complaint by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.
On September 4, 2009, the PUCO opened a case to take comments from Ohio’s stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public meeting on September 15, 2009 to answer questions regarding the RTO consolidation.
Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesnean exit fee to remainMISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and provide forMISO. The result of these comments and protests could delay or otherwise have a methodology for Duquesne to meetmaterial financial effect on the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.
proposed RTO consolidation.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks.discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties have filed requests for rehearing of the March 26, 2009 Order. In addition,On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.
PJM has indefinitely postponedreconvened the technical conference on RPM grantedCapacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes were approved by the FERC in an order of September 19, 2008.issued on October 30, 2009, and are effective November 1, 2009. The CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement iswas proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.
On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to startwas implemented as planned effectiveon June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.
FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of thea December 23, 2008 waiver.waiver of restrictions on affiliate sales without prior approval of the FERC.
On October 31, 2008,May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES executed a Third Restated Partial Requirements Agreementwas the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with Met-Ed, Penelec, and Waverly effective Novemberusage beginning June 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009, and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.
Environmental Matters
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $808 million for the period 2009-2013.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achievedcontinuing through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).May 31, 2011.
On May 22, 2007, FirstEnergyNovember 3, 2009, FES, Met-Ed, Penelec and FGCO received a notice letter, required 60 days priorWaverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FirstEnergy’s only Pennsylvania coal-fired power plant, until 2015, if at all.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducinglimit the amount of man-made GHG, including CO2, emittedcapacity resources required to be supplied by developed countries by 2012. The United States signedFES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010. Under the Kyoto Protocolnew agreement, Met-Ed, Penelec, and Waverly (Buyers) assign 1300 MW of existing energy purchases to FES to assist it in 1998 but it was never submitted for ratification bysupplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, 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 large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration optionassigned power from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’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. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. The future cost of compliance with coal combustion waste regulations may be substantial and will depend, in part, on the regulatory action taken by the EPA and implementation by the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigationthird party into the causes ofmarket or use it to serve the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding, the Muise class action) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
After various motions, rulings and appeals, the Plaintiffs' claimsMet-Ed/Penelec load. FES is responsible for consumer fraud, common law fraud, negligent misrepresentation, strict product liability, and punitive damages were dismissed, leaving only the negligence and breach of contract causes of actions. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.
Nuclear Plant Matters
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.
In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for anobtaining additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FirstEnergy has a strike mitigation plan readysupplies in the event of a strike.
failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The union employeesFourth Restated Partial Requirements Agreement terminates at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation plan ready in the eventend of a strike. 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.2010.
11. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and expects to expand its disclosures regarding the fair value of financial instruments.
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidancea standard on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSPstandard is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets.
In June 2009, the FASB amended the derecognition guidance in the Transfers and Servicing Topic of the FASB Accounting Standards Codification and eliminated the concept of a QSPE. The amended guidance requires an evaluation of all existing QSPEs to determine whether they must be consolidated. This standard is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.
In June 2009, the FASB amended the consolidation guidance applied to VIEs. This standard replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. This standard also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. The standard is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this standard on its financial statements.
In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance in determining fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for the first reporting period, including interim periods, beginning after issuance, or October 1, 2009, for FirstEnergy. FirstEnergy does not expect this standard to have a material effect upon its financial statements.
12. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable operating segments." FES and the Utilities do not have separate reportable operating segments.
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy's Pennsylvania and New Jersey electric utility subsidiaries. Its revenues are primarily derived from the delivery of electricity, cost recovery of regulatory assets, and default service electric generation sales to non-shopping customers in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under Met-Ed's and Penelec's partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland, Michigan and Illinois, owns or leases and operates FirstEnergy's generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from affiliated and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO to deliver electricity to the segment's customers. The segment's internal revenues represent sales to its affiliates in Ohio and Pennsylvania.
The Ohio transitional generation services segment represents the generation commodity operations of FirstEnergy's Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligations of the Ohio Companies. Its results reflect the purchase of electricity from third parties and the competitive energy services segment through a CBP, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related to the delivery of generation load. This segment's total assets consist primarily of accounts receivable for generation revenues from retail customers.
Segment Financial Information | | | | | | | | | | | | | | | | | | | | | | | | | Ohio | | | | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | | | | | | | | | | | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | | Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | | | | (In millions) | | September 30, 2009 | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,203 | | | $ | 490 | | | $ | 739 | | | $ | 6 | | | $ | (30 | ) | | $ | 3,408 | | Internal revenues | | | - | | | | 617 | | | | - | | | | - | | | | (617 | ) | | | - | | Total revenues | | | 2,203 | | | | 1,107 | | | | 739 | | | | 6 | | | | (647 | ) | | | 3,408 | | Depreciation and amortization | | | 356 | | | | 69 | | | | 17 | | | | 3 | | | | 4 | | | | 449 | | Investment income | | | 46 | | | | 159 | | | | - | | | | - | | | | (14 | ) | | | 191 | | Net interest charges | | | 117 | | | | 28 | | | | - | | | | 2 | | | | 173 | | | | 320 | | Income taxes | | | 93 | | | | 121 | | | | 6 | | | | (19 | ) | | | (73 | ) | | | 128 | | Net income (loss) | | | 139 | | | | 183 | | | | 9 | | | | 17 | | | | (118 | ) | | | 230 | | Total assets | | | 22,753 | | | | 10,691 | | | | 270 | | | | 674 | | | | 286 | | | | 34,674 | | Total goodwill | | | 5,551 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,575 | | Property additions | | | 182 | | | | 224 | | | | - | | | | 14 | | | | 12 | | | | 432 | | | | | | | | | | | | | | | | | | | | | | | | | | | September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,657 | | | $ | 460 | | | $ | 813 | | | $ | 5 | | | $ | (31 | ) | | $ | 3,904 | | Internal revenues | | | - | | | | 786 | | | | - | | | | - | | | | (786 | ) | | | - | | Total revenues | | | 2,657 | | | | 1,246 | | | | 813 | | | | 5 | | | | (817 | ) | | | 3,904 | | Depreciation and amortization | | | 286 | | | | 67 | | | | 46 | | | | 1 | | | | 1 | | | | 401 | | Investment income | | | 48 | | | | 13 | | | | 1 | | | | - | | | | (22 | ) | | | 40 | | Net interest charges | | | 101 | | | | 31 | | | | 1 | | | | - | | | | 44 | | | | 177 | | Income taxes | | | 188 | | | | 109 | | | | 14 | | | | (46 | ) | | | (27 | ) | | | 238 | | Net income | | | 283 | | | | 164 | | | | 19 | | | | 48 | | | | (43 | ) | | | 471 | | Total assets | | | 23,088 | | | | 9,360 | | | | 270 | | | | 457 | | | | 387 | | | | 33,562 | | Total goodwill | | | 5,559 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,583 | | Property additions | | | 170 | | | | 285 | | | | - | | | | 85 | | | | 20 | | | | 560 | | | | | | | | | | | | | | | | | | | | | | | | | | | Nine Months Ended | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | September 30, 2009 | | | | | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 6,236 | | | $ | 1,329 | | | $ | 2,519 | | | $ | 18 | | | $ | (89 | ) | | $ | 10,013 | | Internal revenues | | | - | | | | 2,349 | | | | - | | | | - | | | | (2,349 | ) | | | - | | Total revenues | | | 6,236 | | | | 3,678 | | | | 2,519 | | | | 18 | | | | (2,438 | ) | | | 10,013 | | Depreciation and amortization | | | 1,122 | | | | 201 | | | | (24 | ) | | | 7 | | | | 11 | | | | 1,317 | | Investment income | | | 110 | | | | 136 | | | | 1 | | | | - | | | | (40 | ) | | | 207 | | Net interest charges | | | 340 | | | | 64 | | | | - | | | | 5 | | | | 250 | | | | 659 | | Income taxes | | | 154 | | | | 409 | | | | 36 | | | | (56 | ) | | | (113 | ) | | | 430 | | Net income (loss) | | | 230 | | | | 614 | | | | 55 | | | | 52 | | | | (197 | ) | | | 754 | | Total assets | | | 22,753 | | | | 10,691 | | | | 270 | | | | 674 | | | | 286 | | | | 34,674 | | Total goodwill | | | 5,551 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,575 | | Property additions | | | 524 | | | | 893 | | | | - | | | | 133 | | | | 25 | | | | 1,575 | | | | | | | | | | | | | | | | | | | | | | | | | | | September 30, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 7,051 | | | $ | 1,164 | | | $ | 2,203 | | | $ | 65 | | | $ | (57 | ) | | $ | 10,426 | | Internal revenues | | | - | | | | 2,266 | | | | - | | | | - | | | | (2,266 | ) | | | - | | Total revenues | | | 7,051 | | | | 3,430 | | | | 2,203 | | | | 65 | | | | (2,323 | ) | | | 10,426 | | Depreciation and amortization | | | 782 | | | | 179 | | | | 61 | | | | 2 | | | | 10 | | | | 1,034 | | Investment income | | | 133 | | | | (1 | ) | | | 1 | | | | 6 | | | | (66 | ) | | | 73 | | Net interest charges | | | 303 | | | | 86 | | | | 1 | | | | - | | | | 133 | | | | 523 | | Income taxes | | | 436 | | | | 212 | | | | 42 | | | | (33 | ) | | | (72 | ) | | | 585 | | Net income | | | 655 | | | | 317 | | | | 62 | | | | 96 | | | | (119 | ) | | | 1,011 | | Total assets | | | 23,088 | | | | 9,360 | | | | 270 | | | | 457 | | | | 387 | | | | 33,562 | | Total goodwill | | | 5,559 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,583 | | Property additions | | | 621 | | | | 1,430 | | | | - | | | | 106 | | | | 20 | | | | 2,177 | |
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
13. SUPPLEMENTAL GUARANTOR INFORMATION
On July 13, 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully, unconditionally and irrevocably guaranteed all of FGCO'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 resultfinancing for FGCO.
The condensed consolidating statements of this FSP.income for the three-month and nine-month periods ended September 30, 2009 and 2008, consolidating balance sheets as of September 30, 2009 and December 31, 2008 and consolidating statements of cash flows for the nine months ended September 30, 2009 and 2008 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.
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 1,087,991 | | | $ | 477,679 | | | $ | 170,129 | | | $ | (631,227 | ) | | $ | 1,104,572 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 9,278 | | | | 241,953 | | | | 43,462 | | | | - | | | | 294,693 | | Purchased power from non-affiliates | | | 205,200 | | | | - | | | | - | | | | - | | | | 205,200 | | Purchased power from affiliates | | | 621,996 | | | | 9,233 | | | | 35,290 | | | | (631,229 | ) | | | 35,290 | | Other operating expenses | | | 70,246 | | | | 109,828 | | | | 113,669 | | | | 12,192 | | | | 305,935 | | Provision for depreciation | | | 1,051 | | | | 30,469 | | | | 35,832 | | | | (1,311 | ) | | | 66,041 | | General taxes | | | 4,351 | | | | 11,331 | | | | 6,018 | | | | - | | | | 21,700 | | Total expenses | | | 912,122 | | | | 402,814 | | | | 234,271 | | | | (620,348 | ) | | | 928,859 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 175,869 | | | | 74,865 | | | | (64,142 | ) | | | (10,879 | ) | | | 175,713 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 35 | | | | 319 | | | | 158,503 | | | | - | | | | 158,857 | | Miscellaneous income, including net income | | | | | | | | | | | | | | | | | | from equity investees | | | 100,668 | | | | 744 | | | | 1 | | | | (98,609 | ) | | | 2,804 | | Interest expense - affiliates | | | (35 | ) | | | (1,267 | ) | | | (907 | ) | | | - | | | | (2,209 | ) | Interest expense - other | | | (15,358 | ) | | | (26,737 | ) | | | (16,205 | ) | | | 16,113 | | | | (42,187 | ) | Capitalized interest | | | 49 | | | | 15,381 | | | | 2,439 | | | | - | | | | 17,869 | | Total other income (expense) | | | 85,359 | | | | (11,560 | ) | | | 143,831 | | | | (82,496 | ) | | | 135,134 | | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 261,228 | | | | 63,305 | | | | 79,689 | | | | (93,375 | ) | | | 310,847 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 61,545 | | | | 19,646 | | | | 27,801 | | | | 2,172 | | | | 111,164 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 199,683 | | | $ | 43,659 | | | $ | 51,888 | | | $ | (95,547 | ) | | $ | 199,683 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 1,222,783 | | | $ | 574,394 | | | $ | 267,017 | | | $ | (822,590 | ) | | $ | 1,241,604 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 8,177 | | | | 307,646 | | | | 34,123 | | | | - | | | | 349,946 | | Purchased power from non-affiliates | | | 221,493 | | | | - | | | | - | | | | - | | | | 221,493 | | Purchased power from affiliates | | | 815,243 | | | | 7,347 | | | | 15,821 | | | | (822,590 | ) | | | 15,821 | | Other operating expenses | | | 35,596 | | | | 110,701 | | | | 120,697 | | | | 12,190 | | | | 279,184 | | Provision for depreciation | | | 1,978 | | | | 33,432 | | | | 30,559 | | | | (1,336 | ) | | | 64,633 | | General taxes | | | 4,829 | | | | 10,768 | | | | 6,139 | | | | - | | | | 21,736 | | Total expenses | | | 1,087,316 | | | | 469,894 | | | | 207,339 | | | | (811,736 | ) | | | 952,813 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 135,467 | | | | 104,500 | | | | 59,678 | | | | (10,854 | ) | | | 288,791 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Investment income (loss) | | | (122 | ) | | | (1,204 | ) | | | 13,287 | | | | - | | | | 11,961 | | Miscellaneous income, including net income | | | | | | | | | | | | | | | | | | from equity investees | | | 102,899 | | | | 689 | | | | - | | | | (97,122 | ) | | | 6,466 | | Interest expense - affiliates | | | (120 | ) | | | (4,963 | ) | | | (2,932 | ) | | | - | | | | (8,015 | ) | Interest expense - other | | | (8,464 | ) | | | (23,447 | ) | | | (17,183 | ) | | | 16,325 | | | | (32,769 | ) | Capitalized interest | | | 41 | | | | 11,376 | | | | 978 | | | | - | | | | 12,395 | | Total other income (expense) | | | 94,234 | | | | (17,549 | ) | | | (5,850 | ) | | | (80,797 | ) | | | (9,962 | ) | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 229,701 | | | | 86,951 | | | | 53,828 | | | | (91,651 | ) | | | 278,829 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 44,046 | | | | 31,863 | | | | 14,995 | | | | 2,270 | | | | 93,174 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 185,655 | | | $ | 55,088 | | | $ | 38,833 | | | $ | (93,921 | ) | | $ | 185,655 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 3,357,873 | | | $ | 1,726,715 | | | $ | 955,452 | | | $ | (2,368,210 | ) | | $ | 3,671,830 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 16,400 | | | | 755,632 | | | | 99,128 | | | | - | | | | 871,160 | | Purchased power from non-affiliates | | | 551,155 | | | | - | | | | - | | | | - | | | | 551,155 | | Purchased power from affiliates | | | 2,351,879 | | | | 16,333 | | | | 149,746 | | | | (2,368,212 | ) | | | 149,746 | | Other operating expenses | | | 144,284 | | | | 313,416 | | | | 397,284 | | | | 36,571 | | | | 891,555 | | Provision for depreciation | | | 3,087 | | | | 90,680 | | | | 103,135 | | | | (3,940 | ) | | | 192,962 | | General taxes | | | 12,826 | | | | 35,289 | | | | 18,246 | | | | - | | | | 66,361 | | Total expenses | | | 3,079,631 | | | | 1,211,350 | | | | 767,539 | | | | (2,335,581 | ) | | | 2,722,939 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 278,242 | | | | 515,365 | | | | 187,913 | | | | (32,629 | ) | | | 948,891 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 83 | | | | 758 | | | | 134,882 | | | | - | | | | 135,723 | | Miscellaneous income, including net income | | | | | | | | | | | | | | | | | | | | | from equity investees | | | 509,927 | | | | 1,209 | | | | 15 | | | | (498,311 | ) | | | 12,840 | | Interest expense - affiliates | | | (103 | ) | | | (4,648 | ) | | | (3,752 | ) | | | - | | | | (8,503 | ) | Interest expense - other | | | (20,778 | ) | | | (72,762 | ) | | | (46,050 | ) | | | 48,605 | | | | (90,985 | ) | Capitalized interest | | | 146 | | | | 34,257 | | | | 7,572 | | | | - | | | | 41,975 | | Total other income (expense) | | | 489,275 | | | | (41,186 | ) | | | 92,667 | | | | (449,706 | ) | | | 91,050 | | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 767,517 | | | | 474,179 | | | | 280,580 | | | | (482,335 | ) | | | 1,039,941 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 99,751 | | | | 166,902 | | | | 98,893 | | | | 6,629 | | | | 372,175 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 667,766 | | | $ | 307,277 | | | $ | 181,687 | | | $ | (488,964 | ) | | $ | 667,766 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 3,387,258 | | | $ | 1,707,320 | | | $ | 879,729 | | | $ | (2,562,309 | ) | | $ | 3,411,998 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 13,920 | | | | 876,077 | | | | 92,188 | | | | - | | | | 982,185 | | Purchased power from non-affiliates | | | 648,556 | | | | - | | | | - | | | | - | | | | 648,556 | | Purchased power from affiliates | | | 2,549,892 | | | | 12,417 | | | | 75,834 | | | | (2,562,309 | ) | | | 75,834 | | Other operating expenses | | | 103,034 | | | | 342,041 | | | | 381,826 | | | | 36,567 | | | | 863,468 | | Provision for depreciation | | | 3,885 | | | | 90,058 | | | | 80,646 | | | | (4,054 | ) | | | 170,535 | | General taxes | | | 14,971 | | | | 33,842 | | | | 15,915 | | | | - | | | | 64,728 | | Total expenses | | | 3,334,258 | | | | 1,354,435 | | | | 646,409 | | | | (2,529,796 | ) | | | 2,805,306 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 53,000 | | | | 352,885 | | | | 233,320 | | | | (32,513 | ) | | | 606,692 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Investment loss | | | (333 | ) | | | (3,300 | ) | | | (2,699 | ) | | | - | | | | (6,332 | ) | Miscellaneous income, including net income | | | | | | | | | | | | | | | | | | | | | from equity investees | | | 323,425 | | | | 2,066 | | | | - | | | | (305,710 | ) | | | 19,781 | | Interest expense - affiliates | | | (252 | ) | | | (18,172 | ) | | | (7,529 | ) | | | - | | | | (25,953 | ) | Interest expense - other | | | (19,105 | ) | | | (73,112 | ) | | | (38,833 | ) | | | 49,241 | | | | (81,809 | ) | Capitalized interest | | | 90 | | | | 27,460 | | | | 2,049 | | | | - | | | | 29,599 | | Total other income (expense) | | | 303,825 | | | | (65,058 | ) | | | (47,012 | ) | | | (256,469 | ) | | | (64,714 | ) | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 356,825 | | | | 287,827 | | | | 186,308 | | | | (288,982 | ) | | | 541,978 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 13,092 | | | | 109,615 | | | | 68,597 | | | | 6,941 | | | | 198,245 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 343,733 | | | $ | 178,212 | | | $ | 117,711 | | | $ | (295,923 | ) | | $ | 343,733 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING BALANCE SHEETS | | (Unaudited) | | | | | | | | | | | | | | | | | | As of September 30, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | ASSETS | | | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | 266,859 | | | $ | 99 | | | $ | - | | | $ | - | | | $ | 266,958 | | Receivables- | | | | | | | | | | | | | | | | | | | | | Customers | | | 155,489 | | | | - | | | | - | | | | - | | | | 155,489 | | Associated companies | | | 278,670 | | | | 186,263 | | | | 106,551 | | | | (227,097 | ) | | | 344,387 | | Other | | | 15,310 | | | | 12,858 | | | | 19,411 | | | | - | | | | 47,579 | | Notes receivable from associated companies | | | 134,283 | | | | 200,692 | | | | 93,041 | | | | - | | | | 428,016 | | Materials and supplies, at average cost | | | 9,925 | | | | 304,358 | | | | 213,995 | | | | - | | | | 528,278 | | Prepayments and other | | | 90,377 | | | | 19,064 | | | | 10,921 | | | | - | | | | 120,362 | | | | | 950,913 | | | | 723,334 | | | | 443,919 | | | | (227,097 | ) | | | 1,891,069 | | | | | | | | | | | | | | | | | | | | | | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | | In service | | | 90,179 | | | | 5,508,790 | | | | 5,041,783 | | | | (386,054 | ) | | | 10,254,698 | | Less - Accumulated provision for depreciation | | | 12,590 | | | | 2,785,417 | | | | 1,860,060 | | | | (170,235 | ) | | | 4,487,832 | | | | | 77,589 | | | | 2,723,373 | | | | 3,181,723 | | | | (215,819 | ) | | | 5,766,866 | | Construction work in progress | | | 4,179 | | | | 1,830,141 | | | | 361,679 | | | | - | | | | 2,195,999 | | | | | 81,768 | | | | 4,553,514 | | | | 3,543,402 | | | | (215,819 | ) | | | 7,962,865 | | | | | | | | | | | | | | | | | | | | | | | INVESTMENTS: | | | | | | | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,101,884 | | | | - | | | | 1,101,884 | | Investment in associated companies | | | 4,327,059 | | | | - | | | | - | | | | (4,327,059 | ) | | | - | | Long-term notes receivable from associated companies | | | - | | | | - | | | | 8,817 | | | | - | | | | 8,817 | | Other | | | 1,320 | | | | 25,121 | | | | 201 | | | | - | | | | 26,642 | | | | | 4,328,379 | | | | 25,121 | | | | 1,110,902 | | | | (4,327,059 | ) | | | 1,137,343 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | Accumulated deferred income taxes | | | 12,331 | | | | 391,899 | | | | - | | | | (366,131 | ) | | | 38,099 | | Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | | Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Unamortized sale and leaseback costs | | | - | | | | 2,938 | | | | - | | | | 55,412 | | | | 58,350 | | Other | | | 194,916 | | | | 68,278 | | | | 16,619 | | | | (53,679 | ) | | | 226,134 | | | | | 231,495 | | | | 561,965 | | | | 39,229 | | | | (364,398 | ) | | | 468,291 | | | | $ | 5,592,555 | | | $ | 5,863,934 | | | $ | 5,137,452 | | | $ | (5,134,373 | ) | | $ | 11,459,568 | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Currently payable long-term debt | | $ | 726 | | | $ | 697,986 | | | $ | 951,240 | | | $ | (18,186 | ) | | $ | 1,631,766 | | Short-term borrowings- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | - | | | | - | | | | - | | | | - | | | | - | | Other | | | 100,000 | | | | - | | | | - | | | | - | | | | 100,000 | | Accounts payable- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 130,669 | | | | 212,778 | | | | 234,626 | | | | (190,891 | ) | | | 387,182 | | Other | | | 30,890 | | | | 125,163 | | | | - | | | | - | | | | 156,053 | | Accrued taxes | | | 114,043 | | | | 29,489 | | | | 16,791 | | | | (54,749 | ) | | | 105,574 | | Other | | | 41,828 | | | | 120,107 | | | | 27,772 | | | | 38,081 | | | | 227,788 | | | | | 418,156 | | | | 1,185,523 | | | | 1,230,429 | | | | (225,745 | ) | | | 2,608,363 | | | | | | | | | | | | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | | Common stockholder's equity | | | 3,607,283 | | | | 2,252,002 | | | | 2,054,817 | | | | (4,306,819 | ) | | | 3,607,283 | | Long-term debt and other long-term obligations | | | 1,519,585 | | | | 1,865,313 | | | | 533,990 | | | | (1,278,796 | ) | | | 2,640,092 | | | | | 5,126,868 | | | | 4,117,315 | | | | 2,588,807 | | | | (5,585,615 | ) | | | 6,247,375 | | | | | | | | | | | | | | | | | | | | | | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,001,298 | | | | 1,001,298 | | Accumulated deferred income taxes | | | - | | | | - | | | | 324,311 | | | | (324,311 | ) | | | - | | Accumulated deferred investment tax credits | | | - | | | | 37,129 | | | | 22,350 | | | | - | | | | 59,479 | | Asset retirement obligations | | | - | | | | 25,011 | | | | 881,188 | | | | - | | | | 906,199 | | Retirement benefits | | | 32,043 | | | | 168,054 | | | | - | | | | - | | | | 200,097 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Lease market valuation liability | | | - | | | | 273,624 | | | | - | | | | - | | | | 273,624 | | Other | | | 15,488 | | | | 29,784 | | | | 67,757 | | | | - | | | | 113,029 | | | | | 47,531 | | | | 561,096 | | | | 1,318,216 | | | | 676,987 | | | | 2,603,830 | | | | $ | 5,592,555 | | | $ | 5,863,934 | | | $ | 5,137,452 | | | $ | (5,134,373 | ) | | $ | 11,459,568 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING BALANCE SHEETS | | (Unaudited) | | | | | | | | | | | | | | | | | | As of December 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | ASSETS | | | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | - | | | $ | 39 | | | $ | - | | | $ | - | | | $ | 39 | | Receivables- | | | | | | | | | | | | | | | | | | | | | Customers | | | 86,123 | | | | - | | | | - | | | | - | | | | 86,123 | | Associated companies | | | 363,226 | | | | 225,622 | | | | 113,067 | | | | (323,815 | ) | | | 378,100 | | Other | | | 991 | | | | 11,379 | | | | 12,256 | | | | - | | | | 24,626 | | Notes receivable from associated companies | | | 107,229 | | | | 21,946 | | | | - | | | | - | | | | 129,175 | | Materials and supplies, at average cost | | | 5,750 | | | | 303,474 | | | | 212,537 | | | | - | | | | 521,761 | | Prepayments and other | | | 76,773 | | | | 35,102 | | | | 660 | | | | - | | | | 112,535 | | | | | 640,092 | | | | 597,562 | | | | 338,520 | | | | (323,815 | ) | | | 1,252,359 | | | | | | | | | | | | | | | | | | | | | | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | | In service | | | 134,905 | | | | 5,420,789 | | | | 4,705,735 | | | | (389,525 | ) | | | 9,871,904 | | Less - Accumulated provision for depreciation | | | 13,090 | | | | 2,702,110 | | | | 1,709,286 | | | | (169,765 | ) | | | 4,254,721 | | | | | 121,815 | | | | 2,718,679 | | | | 2,996,449 | | | | (219,760 | ) | | | 5,617,183 | | Construction work in progress | | | 4,470 | | | | 1,441,403 | | | | 301,562 | | | | - | | | | 1,747,435 | | | | | 126,285 | | | | 4,160,082 | | | | 3,298,011 | | | | (219,760 | ) | | | 7,364,618 | | | | | | | | | | | | | | | | | | | | | | | INVESTMENTS: | | | | | | | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,033,717 | | | | - | | | | 1,033,717 | | Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | | Investment in associated companies | | | 3,596,152 | | | | - | | | | - | | | | (3,596,152 | ) | | | - | | Other | | | 1,913 | | | | 59,476 | | | | 202 | | | | - | | | | 61,591 | | | | | 3,598,065 | | | | 59,476 | | | | 1,096,819 | | | | (3,596,152 | ) | | | 1,158,208 | | | | | | | | | | | | | | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | Accumulated deferred income tax benefits | | | 24,703 | | | | 476,611 | | | | - | | | | (233,552 | ) | | | 267,762 | | Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | | Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Unamortized sale and leaseback costs | | | - | | | | 20,286 | | | | - | | | | 49,646 | | | | 69,932 | | Other | | | 59,642 | | | | 59,674 | | | | 21,743 | | | | (44,625 | ) | | | 96,434 | | | | | 108,593 | | | | 655,421 | | | | 44,353 | | | | (228,531 | ) | | | 579,836 | | | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Currently payable long-term debt | | $ | 5,377 | | | $ | 925,234 | | | $ | 1,111,183 | | | $ | (16,896 | ) | | $ | 2,024,898 | | Short-term borrowings- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 1,119 | | �� | | 257,357 | | | | 6,347 | | | | - | | | | 264,823 | | Other | | | 1,000,000 | | | | - | | | | - | | | | - | | | | 1,000,000 | | Accounts payable- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 314,887 | | | | 221,266 | | | | 250,318 | | | | (314,133 | ) | | | 472,338 | | Other | | | 35,367 | | | | 119,226 | | | | - | | | | - | | | | 154,593 | | Accrued taxes | | | 8,272 | | | | 60,385 | | | | 30,790 | | | | (19,681 | ) | | | 79,766 | | Other | | | 61,034 | | | | 136,867 | | | | 13,685 | | | | 36,853 | | | | 248,439 | | | | | 1,426,056 | | | | 1,720,335 | | | | 1,412,323 | | | | (313,857 | ) | | | 4,244,857 | | | | | | | | | | | | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | | Common stockholder's equity | | | 2,944,423 | | | | 1,832,678 | | | | 1,752,580 | | | | (3,585,258 | ) | | | 2,944,423 | | Long-term debt and other long-term obligations | | | 61,508 | | | | 1,328,921 | | | | 469,839 | | | | (1,288,820 | ) | | | 571,448 | | | | | 3,005,931 | | | | 3,161,599 | | | | 2,222,419 | | | | (4,874,078 | ) | | | 3,515,871 | | | | | | | | | | | | | | | | | | | | | | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,026,584 | | | | 1,026,584 | | Accumulated deferred income taxes | | | - | | | | - | | | | 206,907 | | | | (206,907 | ) | | | - | | Accumulated deferred investment tax credits | | | - | | | | 39,439 | | | | 23,289 | | | | - | | | | 62,728 | | Asset retirement obligations | | | - | | | | 24,134 | | | | 838,951 | | | | - | | | | 863,085 | | Retirement benefits | | | 22,558 | | | | 171,619 | | | | - | | | | - | | | | 194,177 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Lease market valuation liability | | | - | | | | 307,705 | | | | - | | | | - | | | | 307,705 | | Other | | | 18,490 | | | | 20,216 | | | | 51,204 | | | | - | | | | 89,910 | | | | | 41,048 | | | | 590,607 | | | | 1,142,961 | | | | 819,677 | | | | 2,594,293 | | | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | NET CASH PROVIDED FROM OPERATING ACTIVITIES | | $ | (37,990 | ) | | $ | 520,169 | | | $ | 408,364 | | | $ | (8,732 | ) | | $ | 881,811 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | 1,498,087 | | | | 524,710 | | | | 333,965 | | | | - | | | | 2,356,762 | | Equity contributions from parent | | | - | | | | 100,000 | | | | 150,000 | | | | (250,000 | ) | | | - | | Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | (1,507 | ) | | | (258,583 | ) | | | (366,857 | ) | | | 8,734 | | | | (618,213 | ) | Short-term borrowings, net | | | (901,119 | ) | | | (257,357 | ) | | | (6,347 | ) | | | - | | | | (1,164,823 | ) | Other | | | (11,583 | ) | | | (5,261 | ) | | | (3,160 | ) | | | (2 | ) | | | (20,006 | ) | Net cash provided from financing activities | | | 583,878 | | | | 103,509 | | | | 107,601 | | | | (241,268 | ) | | | 553,720 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | Property additions | | | (2,224 | ) | | | (439,531 | ) | | | (400,845 | ) | | | - | | | | (842,600 | ) | Proceeds from asset sales | | | - | | | | 16,129 | | | | - | | | | - | | | | 16,129 | | Sales of investment securities held in trusts | | | - | | | | - | | | | 2,152,717 | | | | - | | | | 2,152,717 | | Purchases of investment securities held in trusts | | | - | | | | - | | | | (2,175,135 | ) | | | - | | | | (2,175,135 | ) | Loan to associated companies, net | | | (27,054 | ) | | | (178,746 | ) | | | (93,041 | ) | | | - | | | | (298,841 | ) | Investment in subsidiary | | | (250,000 | ) | | | - | | | | - | | | | 250,000 | | | | - | | Other | | | 249 | | | | (21,470 | ) | | | 339 | | | | - | | | | (20,882 | ) | Net cash used for investing activities | | | (279,029 | ) | | | (623,618 | ) | | | (515,965 | ) | | | 250,000 | | | | (1,168,612 | ) | | | | | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | 266,859 | | | | 60 | | | | - | | | | - | | | | 266,919 | | Cash and cash equivalents at beginning of period | | | - | | | | 39 | | | | - | | | | - | | | | 39 | | Cash and cash equivalents at end of period | | $ | 266,859 | | | $ | 99 | | | $ | - | | | $ | - | | | $ | 266,958 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Nine Months Ended September 30, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | NET CASH PROVIDED FROM OPERATING ACTIVITIES: | | $ | 47,463 | | | $ | 267,933 | | | $ | 247,054 | | | $ | (8,317 | ) | | $ | 554,133 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | - | | | | 328,325 | | | | 209,050 | | | | - | | | | 537,375 | | Equity contribution from parent | | | 280,000 | | | | 675,000 | | | | 175,000 | | | | (850,000 | ) | | | 280,000 | | Short-term borrowings, net | | | 700,000 | | | | - | | | | 139,363 | | | | (91,677 | ) | | | 747,686 | | Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | (1,777 | ) | | | (286,776 | ) | | | (180,666 | ) | | | 8,317 | | | | (460,902 | ) | Short-term borrowings, net | | | - | | | | (91,677 | ) | | | - | | | | 91,677 | | | | - | | Common stock dividend payment | | | (43,000 | ) | | | - | | | | - | | | | - | | | | (43,000 | ) | Net cash provided from financing activities | | | 935,223 | | | | 624,872 | | | | 342,747 | | | | (841,683 | ) | | | 1,061,159 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | Property additions | | | (38,481 | ) | | | (778,329 | ) | | | (600,395 | ) | | | - | | | | (1,417,205 | ) | Proceeds from asset sales | | | - | | | | 15,218 | | | | - | | | | - | | | | 15,218 | | Sales of investment securities held in trusts | | | - | | | | - | | | | 596,291 | | | | - | | | | 596,291 | | Purchases of investment securities held in trusts | | | - | | | | - | | | | (624,899 | ) | | | - | | | | (624,899 | ) | Loan repayments from (loans to) associated companies, net | | | (94,755 | ) | | | (38,399 | ) | | | 69,012 | | | | - | | | | (64,142 | ) | Investment in subsidiary | | | (850,000 | ) | | | - | | | | - | | | | 850,000 | | | | - | | Restricted funds for debt redemption | | | - | | | | (52,090 | ) | | | (29,550 | ) | | | - | | | | (81,640 | ) | Other | | | 550 | | | | (39,205 | ) | | | (260 | ) | | | - | | | | (38,915 | ) | Net cash used for investing activities | | | (982,686 | ) | | | (892,805 | ) | | | (589,801 | ) | | | 850,000 | | | | (1,615,292 | ) | | | | | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | | Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | | Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Report of Independent Registered Public Accounting Firm
To the Stockholders and Board of Directors of FirstEnergy Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 67 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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FIRSTENERGY CORP. | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | Three Months Ended | | | March 31 | | | | | | | | | 2009 | | | 2008 | | | (In millions, except | | | per share amounts) | | REVENUES: | | | | | | Electric utilities | $ | 3,020 | | | $ | 2,913 | | Unregulated businesses | | 314 | | | | 364 | | Total revenues* | | 3,334 | | | | 3,277 | | | | | | | | | | EXPENSES: | | | | | | | | Fuel | | 312 | | | | 328 | | Purchased power | | 1,143 | | | | 1,000 | | Other operating expenses | | 827 | | | | 799 | | Provision for depreciation | | 177 | | | | 164 | | Amortization of regulatory assets | | 411 | | | | 258 | | Deferral of new regulatory assets | | (93 | ) | | | (105 | ) | General taxes | | 211 | | | | 215 | | Total expenses | | 2,988 | | | | 2,659 | | | | | | | | | | OPERATING INCOME | | 346 | | | | 618 | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | Investment income (loss), net | | (11 | ) | | | 17 | | Interest expense | | (194 | ) | | | (179 | ) | Capitalized interest | | 28 | | | | 8 | | Total other expense | | (177 | ) | | | (154 | ) | | | | | | | | | INCOME BEFORE INCOME TAXES | | 169 | | | | 464 | | | | | | | | | | INCOME TAXES | | 54 | | | | 187 | | | | | | | | | | NET INCOME | | 115 | | | | 277 | | | | | | | | | | Less: Noncontrolling interest income (loss) | | (4 | ) | | | 1 | | | | | | | | | | EARNINGS AVAILABLE TO PARENT | $ | 119 | | | $ | 276 | | | | | | | | | | | | | | | | | | BASIC EARNINGS PER SHARE OF COMMON STOCK | $ | 0.39 | | | $ | 0.91 | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING | | 304 | | | | 304 | | | | | | | | | | DILUTED EARNINGS PER SHARE OF COMMON STOCK | $ | 0.39 | | | $ | 0.90 | | | | | | | | | | WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING | | 306 | | | | 307 | | | | | | | | | | DIVIDENDS DECLARED PER SHARE OF COMMON STOCK | $ | 0.55 | | | $ | 0.55 | | | | | | | | | | | | | | | | | | * Includes $109 million and $114 million of excise tax collections in the first quarter of 2009 and 2008, respectively. | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. | |
FIRSTENERGY CORP. | | | | | | | | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | Three Months Ended | | | March 31 | | | 2009 | | | 2008 | | | (In millions) | | | | | | | | NET INCOME | $ | 115 | | | $ | 277 | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | Pension and other postretirement benefits | | 35 | | | | (20 | ) | Unrealized gain (loss) on derivative hedges | | 15 | | | | (13 | ) | Change in unrealized gain on available-for-sale securities | | (5 | ) | | | (58 | ) | Other comprehensive income (loss) | | 45 | | | | (91 | ) | Income tax expense (benefit) related to other comprehensive income | | 15 | | | | (33 | ) | Other comprehensive income (loss), net of tax | | 30 | | | | (58 | ) | | | | | | | | | COMPREHENSIVE INCOME | | 145 | | | | 219 | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | (4 | ) | | | 1 | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | $ | 149 | | | $ | 218 | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral part of these statements. | |
FIRSTENERGY CORP. | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | March 31, | | | December 31, | | | 2009 | | | 2008 | | | (In millions) | | ASSETS | | | | | | | | | | | | CURRENT ASSETS: | | | | | | Cash and cash equivalents | $ | 399 | | | $ | 545 | | Receivables- | | | | | | | | Customers (less accumulated provisions of $27 million and $28 million, | | | | | | | | respectively, for uncollectible accounts) | | 1,266 | | | | 1,304 | | Other (less accumulated provisions of $9 million for uncollectible accounts) | | 159 | | | | 167 | | Materials and supplies, at average cost | | 657 | | | | 605 | | Prepaid taxes | | 318 | | | | 283 | | Other | | 205 | | | | 149 | | | | 3,004 | | | | 3,053 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | In service | | 26,757 | | | | 26,482 | | Less - Accumulated provision for depreciation | | 10,947 | | | | 10,821 | | | | 15,810 | | | | 15,661 | | Construction work in progress | | 2,397 | | | | 2,062 | | | | 18,207 | | | | 17,723 | | INVESTMENTS: | | | | | | | | Nuclear plant decommissioning trusts | | 1,649 | | | | 1,708 | | Investments in lease obligation bonds | | 561 | | | | 598 | | Other | | 689 | | | | 711 | | | | 2,899 | | | | 3,017 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | Goodwill | | 5,575 | | | | 5,575 | | Regulatory assets | | 2,938 | | | | 3,140 | | Power purchase contract asset | | 340 | | | | 434 | | Other | | 594 | | | | 579 | | | | 9,447 | | | | 9,728 | | | $ | 33,557 | | | $ | 33,521 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | Currently payable long-term debt | $ | 2,144 | | | $ | 2,476 | | Short-term borrowings | | 2,397 | | | | 2,397 | | Accounts payable | | 704 | | | | 794 | | Accrued taxes | | 281 | | | | 333 | | Other | | 1,169 | | | | 1,098 | | | | 6,695 | | | | 7,098 | | CAPITALIZATION: | | | | | | | | Common stockholders’ equity- | | | | | | | | Common stock, $0.10 par value, authorized 375,000,000 shares- | | 31 | | | | 31 | | 304,835,407 shares outstanding | | | | | | | | Other paid-in capital | | 5,459 | | | | 5,473 | | Accumulated other comprehensive loss | | (1,350 | ) | | | (1,380 | ) | Retained earnings | | 4,110 | | | | 4,159 | | Total common stockholders' equity | | 8,250 | | | | 8,283 | | Noncontrolling interest | | 34 | | | | 32 | | Total equity | | 8,284 | | | | 8,315 | | Long-term debt and other long-term obligations | | 9,697 | | | | 9,100 | | | | 17,981 | | | | 17,415 | | NONCURRENT LIABILITIES: | | | | | | | | Accumulated deferred income taxes | | 2,130 | | | | 2,163 | | Asset retirement obligations | | 1,356 | | | | 1,335 | | Deferred gain on sale and leaseback transaction | | 1,018 | | | | 1,027 | | Power purchase contract liability | | 816 | | | | 766 | | Retirement benefits | | 1,896 | | | | 1,884 | | Lease market valuation liability | | 296 | | | | 308 | | Other | | 1,369 | | | | 1,525 | | | | 8,881 | | | | 9,008 | | COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8) | | | | | | | | | $ | 33,557 | | | $ | 33,521 | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements are an integral part of these balance sheets. | | | | | |
FIRSTENERGY CORP. | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | Three Months Ended | | | March 31 | | | 2009 | | | 2008 | | | (In millions) | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | Net Income | $ | 115 | | | $ | 277 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | Provision for depreciation | | 177 | | | | 164 | | Amortization of regulatory assets | | 411 | | | | 258 | | Deferral of new regulatory assets | | (93 | ) | | | (105 | ) | Nuclear fuel and lease amortization | | 27 | | | | 26 | | Deferred purchased power and other costs | | (62 | ) | | | (43 | ) | Deferred income taxes and investment tax credits, net | | (28 | ) | | | 89 | | Investment impairment | | 36 | | | | 16 | | Deferred rents and lease market valuation liability | | (14 | ) | | | 4 | | Stock-based compensation | | (13 | ) | | | (35 | ) | Accrued compensation and retirement benefits | | (66 | ) | | | (142 | ) | Gain on asset sales | | (5 | ) | | | (37 | ) | Electric service prepayment programs | | (8 | ) | | | (19 | ) | Cash collateral received (paid) | | (15 | ) | | | 8 | | Decrease (increase) in operating assets- | | | | | | | | Receivables | | 46 | | | | (6 | ) | Materials and supplies | | (7 | ) | | | (17 | ) | Prepaid taxes | | (34 | ) | | | (100 | ) | Increase (decrease) in operating liabilities- | | | | | | | | Accounts payable | | (90 | ) | | | (23 | ) | Accrued taxes | | (51 | ) | | | (5 | ) | Accrued interest | | 118 | | | | 91 | | Other | | 18 | | | | (42 | ) | Net cash provided from operating activities | | 462 | | | | 359 | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | New Financing- | | | | | | | | Long-term debt | | 700 | | | | - | | Short-term borrowings, net | | - | | | | 746 | | Redemptions and Repayments- | | | | | | | | Long-term debt | | (444 | ) | | | (368 | ) | Net controlled disbursement activity | | (10 | ) | | | 6 | | Common stock dividend payments | | (168 | ) | | | (168 | ) | Other | | (8 | ) | | | 8 | | Net cash provided from financing activities | | 70 | | | | 224 | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | Property additions | | (654 | ) | | | (711 | ) | Proceeds from asset sales | | 8 | | | | 50 | | Sales of investment securities held in trusts | | 567 | | | | 361 | | Purchases of investment securities held in trusts | | (584 | ) | | | (384 | ) | Cash investments | | 17 | | | | 58 | | Other | | (32 | ) | | | (16 | ) | Net cash used for investing activities | | (678 | ) | | | (642 | ) | | | | | | | | | Net change in cash and cash equivalents | | (146 | ) | | | (59 | ) | Cash and cash equivalents at beginning of period | | 545 | | | | 129 | | Cash and cash equivalents at end of period | $ | 399 | | | $ | 70 | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Corp. are an integral | | part of these statements. | | | | | | | |
FIRSTENERGY SOLUTIONS CORP.
ANALYSIS OF RESULTS OF OPERATIONS
FES is a wholly owned subsidiary of FirstEnergy. FES provides energy-related products and services primarily in Ohio, Pennsylvania, Michigan and Maryland, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES’ revenues have been primarily derived from the sale of electricity (provided from FES’ generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond. FES continues to have a partial requirements wholesale power sales agreement with its affiliates, Met-Ed and Penelec, to supply a portion of each of their respective default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty-day written notice prior to the end of the calendar year. FES also supplies, through May 31, 2009, a portion of Penn’s default service requirements at market-based rates as a result of Penn’s 2008 competitive solicitations. FES’ revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES’ participation in its Ohio and Pennsylvania utility affiliates’ power procurement arrangements.
Results of Operations
In the first three months of 2009, net income increased to $171 million from $90 million in the same period in 2008. The increase in net income was primarily due to higher revenues and lower fuel and purchased power costs, partially offset by higher other operating expenses, depreciation and other miscellaneous expenses.
Revenues
Revenues increased by $127 million in the first three months of 2009 compared to the same period in 2008 due to increases in revenues from non-affiliated and affiliated wholesale generation sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:
| | Three Months Ended | | | | | | March 31 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Non-Affiliated Generation Sales: | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | Total Non-Affiliated Generation Sales | | | | | | | | | | ) | Affiliated Generation Sales | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Retail generation sales revenues decreased due to reduced commercial and industrial contract renewals in the PJM market and the termination of certain government aggregation programs in the MISO market that were supplied by FES. Non-affiliated wholesale revenues increased due to higher PJM capacity prices and increased sales volumes in the MISO market, partially offset by lower unit prices and volumes in PJM.
Increased affiliated company wholesale revenues resulted from higher unit prices for sales to the Ohio Companies, under their CBP, partially offset by lower composite prices to the Pennsylvania Companies and an overall decrease in affiliated sales volumes. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the overall composite price to decline. FES supplied less power to the Ohio Companies in the first quarter of 2009 as one of four winning bidders in the Ohio Companies’ RFP process.
The following tables summarize the price and volume factors contributing to changes in revenues from non-affiliated and affiliated generation sales in the first three months of 2009 compared to the same period last year:
| | Increase | | Source of Change in Non-Affiliated Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 57.0% decrease in sales volumes | | $ | (91 | ) | Change in prices | | | | | | | | | ) | Wholesale: | | | | | Effect of 33.9% increase in sales volumes | | | 44 | | Change in prices | | | | | | | | | | Net Decrease in Non-Affiliated Generation Revenues | | | | ) |
| | Increase | | Source of Change in Affiliated Generation Revenues | | | | | | (In millions) | | Ohio Companies: | | | | | Effect of 24.6% decrease in sales volumes | | $ | (142 | ) | Change in prices | | | | | | | | | | Pennsylvania Companies: | | | | | Effect of 11.1% increase in sales volumes | | | 22 | | Change in prices | | | | ) | | | | | | Net Increase in Affiliated Generation Revenues | | | | |
Transmission revenue decreased $8 million due to decreased retail load in the MISO market ($14 million), partially offset by higher PJM congestion revenues ($6 million). Other revenue increased $27 million primarily due to NGC’s lease revenue received from its equity interests in the Beaver Valley Unit 2 and Perry sale and leaseback transactions acquired during the second quarter of 2008.
Expenses
Total expenses decreased by $1 million in the first three months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2009 from the same period last year:
Source of Change in Fuel and Purchased Power | | | | | | (In millions) | | Fossil Fuel: | | | | | Change due to increased unit costs | | $ | 36 | | Change due to volume consumed | | | (52 | ) | | | | (16 | ) | Nuclear Fuel: | | | | | Change due to increased unit costs | | | 1 | | Change due to volume consumed | | | - | | | | | 1 | | Non-affiliated Purchased Power: | | | | | Change due to decreased unit costs | | | (15 | ) | Change due to volume purchased | | | (31 | ) | | | | (46 | ) | Affiliated Purchased Power: | | | | | Change due to increased unit costs | | | 40 | | Change due to volume purchased | | | (3 | ) | | | | 37 | | Net Decrease in Fuel and Purchased Power Costs | | | | ) |
Fossil fuel costs decreased $16 million in the first three months of 2009 primarily as a result of decreased coal consumption, reflecting lower generation. Higher unit prices were due to increased fuel rates on existing coal contracts in the first quarter of 2009. Nuclear fuel costs were relatively unchanged in the first quarter of 2009 from last year.
Purchased power costs from non-affiliates decreased primarily as a result of lower market rates and reduced volume requirements. Purchases from affiliated companies increased as a result of higher unit costs on purchases from the Ohio Companies’ leasehold interests in Beaver Valley Unit 2 and Perry.
Other operating expenses increased by $11 million in the first three months of 2009 from the same period of 2008. The increase was primarily due to 2009 organizational restructuring costs ($4 million) and nuclear operating costs as a result of higher expenses associated with the 2009 Perry refueling outage than incurred with the 2008 Davis-Besse refueling outage ($11 million). Transmission expenses increased as a result of higher congestion charges ($7 million). Partially offsetting the increases were lower fossil contractor costs as a result of rescheduled maintenance activities ($7 million) and lower lease expenses relating to CEI’s and TE’s leasehold improvements in the Mansfield Plant that were transferred to FGCO during the first quarter of 2008 ($5 million).
Depreciation expense increased by $12 million in the first three months of 2009 primarily due to NGC’s acquisition of certain lessor equity interests in the sale and leaseback of Perry and Beaver Valley Unit 2 ($7 million) and property additions since the first quarter of 2008.
Other Expense
Other expense increased by $14 million in the first three months of 2009 from the same period of 2008 primarily due to a greater loss in value of nuclear decommissioning trust investments ($23 million) during the first quarter of 2009. Partially offsetting the higher securities impairments was a $10 million decline in interest expense as a result of higher capitalized interest ($3 million) and lower interest expense to affiliates due to lower rates on loans from the unregulated moneypool ($4 million).
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to FES.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to FES.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of FirstEnergy Solutions Corp.:
We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | | | | | | | | REVENUES: | | | | | | | Electric sales to affiliates | | $ | 892,690 | | | $ | 776,307 | | Electric sales to non-affiliates | | | 279,746 | | | | 288,341 | | Other | | | 53,670 | | | | 34,468 | | Total revenues | | | 1,226,106 | | | | 1,099,116 | | | | | | | | | | | EXPENSES: | | | | | | | | | Fuel | | | 306,158 | | | | 321,689 | | Purchased power from non-affiliates | | | 160,342 | | | | 206,724 | | Purchased power from affiliates | | | 63,207 | | | | 25,485 | | Other operating expenses | | | 307,356 | | | | 296,546 | | Provision for depreciation | | | 61,373 | | | | 49,742 | | General taxes | | | 23,376 | | | | 23,197 | | Total expenses | | | 921,812 | | | | 923,383 | | | | | | | | | | | OPERATING INCOME | | | 304,294 | | | | 175,733 | | | | | | | | | | | OTHER EXPENSE: | | | | | | | | | Miscellaneous expense | | | (26,363 | ) | | | (2,904 | ) | Interest expense to affiliates | | | (2,979 | ) | | | (7,210 | ) | Interest expense - other | | | (22,527 | ) | | | (24,535 | ) | Capitalized interest | | | 10,078 | | | | 6,663 | | Total other expense | | | (41,791 | ) | | | (27,986 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 262,503 | | | | 147,747 | | | | | | | | | | | INCOME TAXES | | | 91,822 | | | | 57,763 | | | | | | | | | | | NET INCOME | | | 170,681 | | | | 89,984 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 2,568 | | | | (1,820 | ) | Unrealized gain on derivative hedges | | | 11,016 | | | | 5,718 | | Change in unrealized gain on available-for-sale securities | | | (1,477 | ) | | | (51,852 | ) | Other comprehensive income (loss) | | | 12,107 | | | | (47,954 | ) | Income tax expense (benefit) related to other comprehensive income | | | 4,709 | | | | (17,403 | ) | Other comprehensive income (loss), net of tax | | | 7,398 | | | | (30,551 | ) | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 178,079 | | | $ | 59,433 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an | | integral part of these statements. | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 34 | | | $ | 39 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,994,000 and $5,899,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 54,554 | | | | 86,123 | | Associated companies | | | 287,935 | | | | 378,100 | | Other (less accumulated provisions of $6,702,000 and $6,815,000 | | | | | | | | | respectively, for uncollectible accounts) | | | 66,293 | | | | 24,626 | | Notes receivable from associated companies | | | 433,137 | | | | 129,175 | | Materials and supplies, at average cost | | | 567,687 | | | | 521,761 | | Prepayments and other | | | 112,162 | | | | 112,535 | | | | | 1,521,802 | | | | 1,252,359 | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | In service | | | 9,912,603 | | | | 9,871,904 | | Less - Accumulated provision for depreciation | | | 4,327,241 | | | | 4,254,721 | | | | | 5,585,362 | | | | 5,617,183 | | Construction work in progress | | | 2,114,831 | | | | 1,747,435 | | | | | 7,700,193 | | | | 7,364,618 | | INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 995,476 | | | | 1,033,717 | | Long-term notes receivable from associated companies | | | 62,900 | | | | 62,900 | | Other | | | 31,898 | | | | 61,591 | | | | | 1,090,274 | | | | 1,158,208 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Accumulated deferred income tax benefits | | | 241,607 | | | | 267,762 | | Lease assignment receivable from associated companies | | | 71,356 | | | | 71,356 | | Goodwill | | | 24,248 | | | | 24,248 | | Property taxes | | | 50,104 | | | | 50,104 | | Unamortized sale and leaseback costs | | | 86,302 | | | | 69,932 | | Other | | | 87,141 | | | | 96,434 | | | | | 560,758 | | | | 579,836 | | | | $ | 10,873,027 | | | $ | 10,355,021 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 1,690,942 | | | $ | 2,024,898 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 786,116 | | | | 264,823 | | Other | | | 1,100,000 | | | | 1,000,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 409,160 | | | | 472,338 | | Other | | | 144,837 | | | | 154,593 | | Accrued taxes | | | 122,734 | | | | 79,766 | | Other | | | 239,984 | | | | 248,439 | | | | | 4,493,773 | | | | 4,244,857 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity - | | | | | | | | | Common stock, without par value, authorized 750 shares, | | | | | | | | | 7 shares outstanding | | | 1,462,133 | | | | 1,464,229 | | Accumulated other comprehensive loss | | | (84,473 | ) | | | (91,871 | ) | Retained earnings | | | 1,742,746 | | | | 1,572,065 | | Total common stockholder's equity | | | 3,120,406 | | | | 2,944,423 | | Long-term debt and other long-term obligations | | | 670,061 | | | | 571,448 | | | | | 3,790,467 | | | | 3,515,871 | | NONCURRENT LIABILITIES: | | | | | | | | | Deferred gain on sale and leaseback transaction | | | 1,018,156 | | | | 1,026,584 | | Accumulated deferred investment tax credits | | | 61,645 | | | | 62,728 | | Asset retirement obligations | | | 877,073 | | | | 863,085 | | Retirement benefits | | | 198,803 | | | | 194,177 | | Property taxes | | | 50,104 | | | | 50,104 | | Lease market valuation liability | | | 296,376 | | | | 307,705 | | Other | | | 86,630 | | | | 89,910 | | | | | 2,588,787 | | | | 2,594,293 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 10,873,027 | | | $ | 10,355,021 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part | | of these balance sheets. | | | | | | | | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 170,681 | | | $ | 89,984 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 61,373 | | | | 49,742 | | Nuclear fuel and lease amortization | | | 27,169 | | | | 25,426 | | Deferred rents and lease market valuation liability | | | (37,522 | ) | | | (34,887 | ) | Deferred income taxes and investment tax credits, net | | | 24,866 | | | | 30,781 | | Investment impairment | | | 33,535 | | | | 14,943 | | Accrued compensation and retirement benefits | | | (3,439 | ) | | | (11,042 | ) | Commodity derivative transactions, net | | | 15,817 | | | | 8,086 | | Gain on asset sales | | | (5,209 | ) | | | (4,964 | ) | Cash collateral, net | | | (5,492 | ) | | | 1,601 | | Decrease (increase) in operating assets: | | | | | | | | | Receivables | | | 80,067 | | | | 69,533 | | Materials and supplies | | | (865 | ) | | | (12,948 | ) | Prepayments and other current assets | | | (3,456 | ) | | | (12,260 | ) | Increase (decrease) in operating liabilities: | | | | | | | | | Accounts payable | | | (61,419 | ) | | | (17,149 | ) | Accrued taxes | | | 39,846 | | | | (28,652 | ) | Accrued interest | | | 10,338 | | | | (728 | ) | Other | | | 1,577 | | | | (7,514 | ) | Net cash provided from operating activities | | | 347,867 | | | | 159,952 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 100,000 | | | | - | | Short-term borrowings, net | | | 621,294 | | | | 1,281,896 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (335,916 | ) | | | (288,603 | ) | Common stock dividend payments | | | - | | | | (10,000 | ) | Net cash provided from financing activities | | | 385,378 | | | | 983,293 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (412,805 | ) | | | (476,529 | ) | Proceeds from asset sales | | | 7,573 | | | | 5,088 | | Sales of investment securities held in trusts | | | 351,414 | | | | 173,123 | | Purchases of investment securities held in trusts | | | (356,904 | ) | | | (181,079 | ) | Loans to associated companies, net | | | (303,963 | ) | | | (644,604 | ) | Other | | | (18,565 | ) | | | (19,244 | ) | Net cash used for investing activities | | | (733,250 | ) | | | (1,143,245 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | (5 | ) | | | - | | Cash and cash equivalents at beginning of period | | | 39 | | | | 2 | | Cash and cash equivalents at end of period | | $ | 34 | | | $ | 2 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to FirstEnergy Solutions Corp. are an integral part of | | these statements. | | | | | | | | |
OHIO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
In the first three months of 2009, net income decreased to $12 million from $44 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009. OE’s financial statements include certain immaterial adjustments that relate to prior periods that reduced net income by $3 million for the first quarter of 2009.
Revenues
Revenues increased by $96 million, or 14.8%, in the first three months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($114 million) and wholesale revenues ($35 million), partially offset by decreases in distribution throughput revenues ($53 million).
Retail generation revenues increased primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflecting a decrease in customer shopping for those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s and Penn’s service territories. Additional generation revenues from OE’s fuel rider effective in January 2009 contributed to the rate variances (see Regulatory Matters – Ohio).
Changes in retail generation sales and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | | | | | | | Residential | | | 11.8 | % | Commercial | | | 17.3 | % | Industrial | | | (8.2 | )% | Net Increase in Generation Sales | | | 7.2 | % |
Retail Generation Revenues | | Increase | | | | (In millions) | | Residential | | $ | 55 | | Commercial | | | 41 | | Industrial | | | 18 | | Increase in Generation Revenues | | $ | 114 | |
Revenues from distribution throughput decreased by $53 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers were a result of the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).
Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period in 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | | | | | | Residential | | | (1.0 | )% | Commercial | | | (4.7 | )% | Industrial | | | (22.9 | )% | Decrease in Distribution Deliveries | | | (9.2 | )% |
Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (8 | ) | Commercial | | | (22 | ) | Industrial | | | (23 | ) | Decrease in Distribution Revenues | | $ | (53 | ) |
Expenses
Total expenses increased by $143 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | | | | | (In millions) | | Purchased power costs | | $ | 130 | | Other operating costs | | | 17 | | Amortization of regulatory assets, net | | | (3 | ) | General taxes | | | (1 | ) | Net Increase in Expenses | | $ | 143 | |
Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009 and higher volumes due to increased retail generation KWH sales. The increase in other operating costs for the first three months of 2009 was primarily due to accruals for economic development programs, in accordance with the PUCO-approved ESP, and energy efficiency obligations. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization in 2008, partially offset by lower MISO transmission cost deferrals and lower RCP distribution deferrals.
Other Expenses
Other expenses increased by $8 million in the first three months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of OE’s $300 million of FMBs in October 2008.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to OE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to OE.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of Ohio Edison Company:
We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 67 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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OHIO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 720,011 | | | $ | 622,271 | | Excise and gross receipts tax collections | | | 28,980 | | | | 30,378 | | Total revenues | | | 748,991 | | | | 652,649 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power from affiliates | | | 332,336 | | | | 319,711 | | Purchased power from non-affiliates | | | 137,813 | | | | 20,475 | | Other operating costs | | | 157,830 | | | | 140,326 | | Provision for depreciation | | | 21,513 | | | | 21,493 | | Amortization of regulatory assets, net | | | 20,211 | | | | 23,127 | | General taxes | | | 49,120 | | | | 50,453 | | Total expenses | | | 718,823 | | | | 575,585 | | | | | | | | | | | OPERATING INCOME | | | 30,168 | | | | 77,064 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Investment income | | | 9,362 | | | | 15,055 | | Miscellaneous expense | | | (810 | ) | | | (3,652 | ) | Interest expense | | | (23,287 | ) | | | (17,641 | ) | Capitalized interest | | | 220 | | | | 110 | | Total other expense | | | (14,515 | ) | | | (6,128 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 15,653 | | | | 70,936 | | | | | | | | | | | INCOME TAXES | | | 4,005 | | | | 26,873 | | | | | | | | | | | NET INCOME | | | 11,648 | | | | 44,063 | | | | | | | | | | | Less: Noncontrolling interest income | | | 146 | | | | 154 | | | | | | | | | | | EARNINGS AVAILABLE TO PARENT | | $ | 11,502 | | | $ | 43,909 | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 11,648 | | | $ | 44,063 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 5,738 | | | | (3,994 | ) | Change in unrealized gain on available-for-sale securities | | | (2,709 | ) | | | (7,571 | ) | Other comprehensive income (loss) | | | 3,029 | | | | (11,565 | ) | Income tax expense (benefit) related to other comprehensive income | | | 529 | | | | (4,262 | ) | Other comprehensive income (loss), net of tax | | | 2,500 | | | | (7,303 | ) | | | | | | | | | | COMPREHENSIVE INCOME | | | 14,148 | | | | 36,760 | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 146 | | | | 154 | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | | $ | 14,002 | | | $ | 36,606 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | of these statements. | | | | | | | | |
OHIO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 311,192 | | | $ | 146,343 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $6,621,000 and $6,065,000, respectively, | | | | | | for uncollectible accounts) | | | 292,159 | | | | 277,377 | | Associated companies | | | 217,455 | | | | 234,960 | | Other (less accumulated provisions of $8,000 and $7,000, respectively, | | | | | | | | | for uncollectible accounts) | | | 19,492 | | | | 14,492 | | Notes receivable from associated companies | | | 77,264 | | | | 222,861 | | Prepayments and other | | | 22,544 | | | | 5,452 | | | | | 940,106 | | | | 901,485 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,915,643 | | | | 2,903,290 | | Less - Accumulated provision for depreciation | | | 1,120,219 | | | | 1,113,357 | | | | | 1,795,424 | | | | 1,789,933 | | Construction work in progress | | | 47,022 | | | | 37,766 | | | | | 1,842,446 | | | | 1,827,699 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Long-term notes receivable from associated companies | | | 256,473 | | | | 256,974 | | Investment in lease obligation bonds | | | 239,501 | | | | 239,625 | | Nuclear plant decommissioning trusts | | | 112,778 | | | | 116,682 | | Other | | | 98,729 | | | | 100,792 | | | | | 707,481 | | | | 714,073 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Regulatory assets | | | 544,782 | | | | 575,076 | | Property taxes | | | 60,542 | | | | 60,542 | | Unamortized sale and leaseback costs | | | 38,880 | | | | 40,130 | | Other | | | 32,418 | | | | 33,710 | | | | | 676,622 | | | | 709,458 | | | | $ | 4,166,655 | | | $ | 4,152,715 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 2,697 | | | $ | 101,354 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 79,810 | | | | - | | Other | | | 1,540 | | | | 1,540 | | Accounts payable- | | | | | | | | | Associated companies | | | 115,778 | | | | 131,725 | | Other | | | 54,237 | | | | 26,410 | | Accrued taxes | | | 72,736 | | | | 77,592 | | Accrued interest | | | 23,717 | | | | 25,673 | | Other | | | 124,871 | | | | 85,209 | | | | | 475,386 | | | | 449,503 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 175,000,000 shares - | | | | | | | | | 60 shares outstanding | | | 1,224,347 | | | | 1,224,416 | | Accumulated other comprehensive loss | | | (181,885 | ) | | | (184,385 | ) | Retained earnings | | | 265,525 | | | | 254,023 | | Total common stockholder's equity | | | 1,307,987 | | | | 1,294,054 | | Noncontrolling interest | | | 7,252 | | | | 7,106 | | Total equity | | | 1,315,239 | | | | 1,301,160 | | Long-term debt and other long-term obligations | | | 1,123,966 | | | | 1,122,247 | | | | | 2,439,205 | | | | 2,423,407 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 650,601 | | | | 653,475 | | Accumulated deferred investment tax credits | | | 12,700 | | | | 13,065 | | Asset retirement obligations | | | 81,944 | | | | 80,647 | | Retirement benefits | | | 305,943 | | | | 308,450 | | Other | | | 200,876 | | | | 224,168 | | | | | 1,252,064 | | | | 1,279,805 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 4,166,655 | | | $ | 4,152,715 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part of | | these balance sheets. | | | | | | | | |
OHIO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 11,648 | | | $ | 44,063 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 21,513 | | | | 21,493 | | Amortization of regulatory assets, net | | | 20,211 | | | | 23,127 | | Purchased power cost recovery reconciliation | | | 2,978 | | | | - | | Amortization of lease costs | | | 32,934 | | | | 32,934 | | Deferred income taxes and investment tax credits, net | | | (7,272 | ) | | | 6,866 | | Accrued compensation and retirement benefits | | | (1,746 | ) | | | (19,482 | ) | Accrued regulatory obligations | | | 18,350 | | | | - | | Electric service prepayment programs | | | (3,944 | ) | | | (10,028 | ) | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | 1,435 | | | | (27,496 | ) | Prepayments and other current assets | | | (9,806 | ) | | | (7,451 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | 11,880 | | | | (3,939 | ) | Accrued taxes | | | (26,222 | ) | | | 2,991 | | Accrued interest | | | (1,956 | ) | | | (5,919 | ) | Other | | | 6,708 | | | | (2,220 | ) | Net cash provided from operating activities | | | 76,711 | | | | 54,939 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | 79,810 | | | | - | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (100,393 | ) | | | (75 | ) | Dividend Payments- | | | | | | | | | Common stock | | | - | | | | (15,000 | ) | Other | | | (69 | ) | | | (5 | ) | Net cash used for financing activities | | | (20,652 | ) | | | (15,080 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (37,523 | ) | | | (49,011 | ) | Sales of investment securities held in trusts | | | 9,417 | | | | 62,344 | | Purchases of investment securities held in trusts | | | (10,422 | ) | | | (63,797 | ) | Loan repayments from associated companies, net | | | 146,098 | | | | 6,534 | | Cash investments | | | (243 | ) | | | 147 | | Other | | | 1,463 | | | | 3,924 | | Net cash provided from (used for) investing activities | | | 108,790 | | | | (39,859 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | 164,849 | | | | - | | Cash and cash equivalents at beginning of period | | | 146,343 | | | | 732 | | Cash and cash equivalents at end of period | | $ | 311,192 | | | $ | 732 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Ohio Edison Company are an integral part | | of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
CEI recognized a net loss of $105 million in the first three months of 2009 compared to net income of $58 million in the same period of 2008. The decrease resulted primarily from CEI’s $216 million regulatory asset impairment related to the implementation of its ESP and increased purchased power costs, partially offset by higher deferrals of new regulatory assets.
Revenues
Revenues increased by $12 million, or 2.8%, in the first three months of 2009 compared to the same period of 2008 primarily due to an increase in retail generation revenues ($18 million), partially offset by decreases in distribution revenues ($4 million) and other miscellaneous revenues ($2 million).
Retail generation revenues increased in the first three months of 2009 due to higher average unit prices across all customer classes and increased sales volume to residential and commercial customers, compared to the same period of 2008. Generation rate increases under CEI’s CBP contributed to the increased rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers primarily reflected a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008.
Changes in retail generation sales and revenues in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| | Residential | | | 8.0 | % | Commercial | | | 12.5 | % | Industrial | | | (9.8 | )% | Net Increase in Retail Generation Sales | | | 1.4 | % |
Retail Generation Revenues | | Increase (Decrease) | | | | (in millions) | | Residential | | $ | 8 | | Commercial | | | 12 | | Industrial | | | (2 | ) | Net Increase in Generation Revenues | | $ | 18 | |
Revenues from distribution throughput decreased by $4 million in the first three months of 2009 compared to the same period of 2008 primarily due lower KWH deliveries to commercial and industrial customers as a result of the economic downturn in CEI’s service territory.
Decreases in distribution KWH deliveries and revenues in the first three months of 2009 compared to the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | Residential | | | (0.6 | )% | Commercial | | | (5.1 | )% | Industrial | | | (19.8 | )% | Decrease in Distribution Deliveries | | | (10.0 | )% |
Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (1 | ) | Commercial | | | (1 | ) | Industrial | | | (2 | ) | Decrease in Distribution Revenues | | $ | (4 | ) |
Expenses
Total expenses increased by $267 million in the first three months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | | | | (in millions) | | Purchased power costs | | $ | 117 | | Amortization of regulatory assets | | | 218 | | Deferral of new regulatory assets | | | (66 | ) | General taxes | | | (2 | ) | Net Increase in Expenses | | $ | 267 | |
Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers in the first quarter of 2009. Increased amortization of regulatory assets was primarily due to the impairment of CEI’s Extended RTC balance in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was primarily due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. While other operating costs were unchanged from the previous year, cost increases associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs were completely offset by reduced transmission expense, labor, contractor costs and general business expense. The decrease in general taxes is primarily due to lower property taxes.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to CEI.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to CEI.
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Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of The Cleveland Electric Illuminating Company:
We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 67 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 431,405 | | | $ | 418,708 | | Excise tax collections | | | 18,320 | | | | 18,600 | | Total revenues | | | 449,725 | | | | 437,308 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power from affiliates | | | 238,872 | | | | 190,196 | | Purchased power from non-affiliates | | | 71,746 | | | | 3,048 | | Other operating costs | | | 64,830 | | | | 65,118 | | Provision for depreciation | | | 18,280 | | | | 19,076 | | Amortization of regulatory assets | | | 256,737 | | | | 38,256 | | Deferral of new regulatory assets | | | (94,816 | ) | | | (29,248 | ) | General taxes | | | 38,141 | | | | 40,083 | | Total expenses | | | 593,790 | | | | 326,529 | | | | | | | | | | | OPERATING INCOME (LOSS) | | | (144,065 | ) | | | 110,779 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Investment income | | | 8,420 | | | | 9,188 | | Miscellaneous income | | | 1,994 | | | | 1,118 | | Interest expense | | | (33,322 | ) | | | (32,520 | ) | Capitalized interest | | | 67 | | | | 196 | | Total other expense | | | (22,841 | ) | | | (22,018 | ) | | | | | | | | | | INCOME (LOSS) BEFORE INCOME TAXES | | | (166,906 | ) | | | 88,761 | | | | | | | | | | | INCOME TAX EXPENSE (BENEFIT) | | | (61,506 | ) | | | 30,326 | | | | | | | | | | | NET INCOME (LOSS) | | | (105,400 | ) | | | 58,435 | | | | | | | | | | | Less: Noncontrolling interest income | | | 458 | | | | 584 | | | | | | | | | | | EARNINGS (LOSS) AVAILABLE TO PARENT | | $ | (105,858 | ) | | $ | 57,851 | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | NET INCOME (LOSS) | | $ | (105,400 | ) | | $ | 58,435 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 3,967 | | | | (213 | ) | Income tax expense related to other comprehensive income | | | 1,370 | | | | 281 | | Other comprehensive income (loss), net of tax | | | 2,597 | | | | (494 | ) | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) | | | (102,803 | ) | | | 57,941 | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 458 | | | | 584 | | | | | | | | | | | COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO PARENT | | $ | (103,261 | ) | | $ | 57,357 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | | Company are an integral part of these statements. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 233 | | | $ | 226 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $6,199,000 and | | | | | | | | | $5,916,000, respectively, for uncollectible accounts) | | | 283,967 | | | | 276,400 | | Associated companies | | | 159,819 | | | | 113,182 | | Other | | | 4,438 | | | | 13,834 | | Notes receivable from associated companies | | | 22,744 | | | | 19,060 | | Prepayments and other | | | 2,002 | | | | 2,787 | | | | | 473,203 | | | | 425,489 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,240,065 | | | | 2,221,660 | | Less - Accumulated provision for depreciation | | | 852,393 | | | | 846,233 | | | | | 1,387,672 | | | | 1,375,427 | | Construction work in progress | | | 40,545 | | | | 40,651 | | | | | 1,428,217 | | | | 1,416,078 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 388,647 | | | | 425,715 | | Other | | | 10,239 | | | | 10,249 | | | | | 398,886 | | | | 435,964 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,688,521 | | | | 1,688,521 | | Regulatory assets | | | 617,967 | | | | 783,964 | | Property taxes | | | 71,500 | | | | 71,500 | | Other | | | 10,629 | | | | 10,818 | | | | | 2,388,617 | | | | 2,554,803 | | | | $ | 4,688,923 | | | $ | 4,832,334 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 150,704 | | | $ | 150,688 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 242,065 | | | | 227,949 | | Accounts payable- | | | | | | | | | Associated companies | | | 94,824 | | | | 106,074 | | Other | | | 26,914 | | | | 7,195 | | Accrued taxes | | | 76,130 | | | | 87,810 | | Accrued interest | | | 41,546 | | | | 13,932 | | Other | | | 44,021 | | | | 40,095 | | | | | 676,204 | | | | 633,743 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity | | | | | | | | | Common stock, without par value, authorized 105,000,000 shares - | | | | | | | | | 67,930,743 shares outstanding | | | 878,680 | | | | 878,785 | | Accumulated other comprehensive loss | | | (132,260 | ) | | | (134,857 | ) | Retained earnings | | | 754,096 | | | | 859,954 | | Total common stockholder's equity | | | 1,500,516 | | | | 1,603,882 | | Noncontrolling interest | | | 20,173 | | | | 22,555 | | Total equity | | | 1,520,689 | | | | 1,626,437 | | Long-term debt and other long-term obligations | | | 1,573,241 | | | | 1,591,586 | | | | | 3,093,930 | | | | 3,218,023 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 644,547 | | | | 704,270 | | Accumulated deferred investment tax credits | | | 12,731 | | | | 13,030 | | Retirement benefits | | | 129,537 | | | | 128,738 | | Lease assignment payable to associated companies | | | 40,827 | | | | 40,827 | | Other | | | 91,147 | | | | 93,703 | | | | | 918,789 | | | | 980,568 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 4,688,923 | | | $ | 4,832,334 | | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | | Company are an integral part of these balance sheets. | | | | | | | | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | | | | | | | | 2009 | | | 2008 | | | | | | | | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income (loss) | | $ | (105,400 | ) | | $ | 58,435 | | Adjustments to reconcile net income (loss) to net cash from operating activities- | | | | | | Provision for depreciation | | | 18,280 | | | | 19,076 | | Amortization of regulatory assets | | | 256,737 | | | | 38,256 | | Deferral of new regulatory assets | | | (94,816 | ) | | | (29,248 | ) | Deferred income taxes and investment tax credits, net | | | (61,525 | ) | | | (4,965 | ) | Accrued compensation and retirement benefits | | | 1,828 | | | | (3,507 | ) | Accrued regulatory obligations | | | 12,057 | | | | - | | Electric service prepayment programs | | | (2,695 | ) | | | (5,847 | ) | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | (44,808 | ) | | | 90,280 | | Prepayments and other current assets | | | 785 | | | | 604 | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | 18,470 | | | | 1,111 | | Accrued taxes | | | (16,274 | ) | | | 23,196 | | Accrued interest | | | 27,614 | | | | 23,831 | | Other | | | 346 | | | | 2,308 | | Net cash provided from operating activities | | | 10,599 | | | | 213,530 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (181 | ) | | | (165 | ) | Short-term borrowings, net | | | (4,086 | ) | | | (177,960 | ) | Dividend Payments- | | | | | | | | | Common stock | | | (10,000 | ) | | | (30,000 | ) | Other | | | (2,840 | ) | | | (2,955 | ) | Net cash used for financing activities | | | (17,107 | ) | | | (211,080 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (24,900 | ) | | | (37,203 | ) | Loans to associated companies, net | | | (3,683 | ) | | | (2,373 | ) | Redemptions of lessor notes | | | 37,068 | | | | 37,709 | | Other | | | (1,970 | ) | | | (574 | ) | Net cash provided from (used for) investing activities | | | 6,515 | | | | (2,441 | ) | | | | | | | | | | Net increase in cash and cash equivalents | | | 7 | | | | 9 | | Cash and cash equivalents at beginning of period | | | 226 | | | | 232 | | Cash and cash equivalents at end of period | | $ | 233 | | | $ | 241 | | | | | | | | | | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Cleveland Electric Illuminating | | Company are an integral part of these statements. | | | | | | | | |
THE TOLEDO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio below for a discussion of Ohio power supply procurement issues for 2009 and beyond.
Results of Operations
Net income in the first three months of 2009 decreased to $1 million from $17 million in the same period of 2008. The decrease resulted primarily from the completion of transition cost recovery in 2008.
Revenues
Revenues increased $33 million, or 15.6%, in the first three months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($67 million), partially offset by lower distribution revenues ($33 million) and wholesale generation revenues ($1 million).
Retail generation revenues increased in the first three months of 2009 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, compared to the same period of 2008. TE’s implementation of a fuel rider in January 2009 produced the rate variances (see Regulatory Matters – Ohio). Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers resulted principally from a decrease in customer shopping. Most of TE’s franchise customers returned to PLR service in December 2008.
Changes in retail electric generation KWH sales and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.
| | Increase | | Retail KWH Sales | | (Decrease) | | | | | | | Residential | | | 6.5 | % | Commercial | | | 39.3 | % | Industrial | | | (11.5 | )% | Net Increase in Retail KWH Sales | | | 3.9 | % |
Retail Generation Revenues | | Increase | | | | (In millions) | | Residential | | $ | 16 | | Commercial | | | 26 | | Industrial | | | 25 | | Increase in Retail Generation Revenues | | $ | 67 | |
Revenues from distribution throughput decreased by $33 million in the first three months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries for all customer classes. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).
Changes in distribution KWH deliveries and revenues in the first three months of 2009 from the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | | | | | | Residential | | | (2.8 | )% | Commercial | | | (10.0 | )% | Industrial | | | (13.5 | )% | Decrease in Distribution Deliveries | | | (9.6 | )% |
Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (8 | ) | Commercial | | | (17 | ) | Industrial | | | (8 | ) | Decrease in Distribution Revenues | | $ | (33 | ) |
Expenses
Total expenses increased $57 million in the first three months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | | | | (In millions) | | | | $ | | | Provision for depreciation | | | | ) | Amortization of regulatory assets, net | | | | | | | | | |
Higher purchased power costs are primarily due to the results of the CBP used for the procurement of electric generation for retail customers during the first quarter of 2009. While other operating costs were unchanged from the first quarter of 2008, cost increases associated with the regulatory obligations for economic development and energy efficiency programs, higher pension and other expenses were completely offset by reduced transmission, labor and other employee benefit expenses. Depreciation expense decreased due to the transfer of leasehold improvements for the Bruce Mansfield Plant and Beaver Valley Unit 2 to FGCO and NGC, respectively, during 2008. The decrease in the net amortization of regulatory assets is primarily due to the cessation of transition cost amortization, partially offset by a reduction in transmission deferrals and the absence of RCP distribution cost deferrals in 2009.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to TE.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to TE.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of The Toledo Edison Company:
We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 67 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | STATEMENTS OF INCOME | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 237,085 | | | $ | 203,669 | | Excise tax collections | | | 7,729 | | | | 8,025 | | Total revenues | | | 244,814 | | | | 211,694 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power from affiliates | | | 125,324 | | | | 99,494 | | Purchased power from non-affiliates | | | 40,537 | | | | 1,804 | | Other operating costs | | | 45,004 | | | | 45,329 | | Provision for depreciation | | | 7,572 | | | | 9,025 | | Amortization of regulatory assets, net | | | 9,897 | | | | 15,531 | | General taxes | | | 14,250 | | | | 14,377 | | Total expenses | | | 242,584 | | | | 185,560 | | | | | | | | | | | OPERATING INCOME | | | 2,230 | | | | 26,134 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Investment income | | | 5,484 | | | | 6,481 | | Miscellaneous expense | | | (1,340 | ) | | | (1,512 | ) | Interest expense | | | (5,533 | ) | | | (6,035 | ) | Capitalized interest | | | 42 | | | | 37 | | Total other expense | | | (1,347 | ) | | | (1,029 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 883 | | | | 25,105 | | | | | | | | | | | INCOME TAX EXPENSE (BENEFIT) | | | (109 | ) | | | 8,088 | | | | | | | | | | | NET INCOME | | | 992 | | | | 17,017 | | | | | | | | | | | Less: Noncontrolling interest income | | | 2 | | | | 2 | | | | | | | | | | | EARNINGS AVAILABLE TO PARENT | | $ | 990 | | | $ | 17,015 | | | | | | | | | | | STATEMENTS OF COMPREHENSIVE INCOME | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 992 | | | $ | 17,017 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 133 | | | | (63 | ) | Change in unrealized gain on available-for-sale securities | | | (809 | ) | | | 1,961 | | Other comprehensive income (loss) | | | (676 | ) | | | 1,898 | | Income tax expense (benefit) related to other comprehensive income | | | (19 | ) | | | 728 | | Other comprehensive income (loss), net of tax | | | (657 | ) | | | 1,170 | | | | | | | | | | | COMPREHENSIVE INCOME | | | 335 | | | | 18,187 | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST | | | 2 | | | | 2 | | | | | | | | | | | COMPREHENSIVE INCOME ATTRIBUTABLE TO PARENT | | $ | 333 | | | $ | 18,185 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company | | are an integral part of these statements. | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 15 | | | $ | 14 | | Receivables- | | | | | | | | | Customers | | | 438 | | | | 751 | | Associated companies | | | 70,444 | | | | 61,854 | | Other (less accumulated provisions of $193,000 and $203,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 23,693 | | | | 23,336 | | Notes receivable from associated companies | | | 133,186 | | | | 111,579 | | Prepayments and other | | | 4,481 | | | | 1,213 | | | | | 232,257 | | | | 198,747 | | UTILITY PLANT: | | | | | | | | | In service | | | 880,315 | | | | 870,911 | | Less - Accumulated provision for depreciation | | | 413,030 | | | | 407,859 | | | | | 467,285 | | | | 463,052 | | Construction work in progress | | | 10,957 | | | | 9,007 | | | | | 478,242 | | | | 472,059 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Investment in lessor notes | | | 124,329 | | | | 142,687 | | Long-term notes receivable from associated companies | | | 37,154 | | | | 37,233 | | Nuclear plant decommissioning trusts | | | 73,235 | | | | 73,500 | | Other | | | 1,646 | | | | 1,668 | | | | | 236,364 | | | | 255,088 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 500,576 | | | | 500,576 | | Regulatory assets | | | 96,351 | | | | 109,364 | | Property taxes | | | 22,970 | | | | 22,970 | | Other | | | 62,004 | | | | 51,315 | | | | | 681,901 | | | | 684,225 | | | | $ | 1,628,764 | | | $ | 1,610,119 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 222 | | | $ | 34 | | Accounts payable- | | | | | | | | | Associated companies | | | 59,462 | | | | 70,455 | | Other | | | 14,823 | | | | 4,812 | | Notes payable to associated companies | | | 107,265 | | | | 111,242 | | Accrued taxes | | | 23,259 | | | | 24,433 | | Lease market valuation liability | | | 36,900 | | | | 36,900 | | Other | | | 54,397 | | | | 22,489 | | | | | 296,328 | | | | 270,365 | | 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 | | | 175,866 | | | | 175,879 | | Accumulated other comprehensive loss | | | (34,029 | ) | | | (33,372 | ) | Retained earnings | | | 191,523 | | | | 190,533 | | Total common stockholder's equity | | | 480,370 | | | | 480,050 | | Noncontrolling interest | | | 2,676 | | | | 2,675 | | Total equity | | | 483,046 | | | | 482,725 | | Long-term debt and other long-term obligations | | | 303,021 | | | | 299,626 | | | | | 786,067 | | | | 782,351 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 77,016 | | | | 78,905 | | Accumulated deferred investment tax credits | | | 6,695 | | | | 6,804 | | Lease market valuation liability | | | 263,875 | | | | 273,100 | | Retirement benefits | | | 74,911 | | | | 73,106 | | Asset retirement obligations | | | 30,719 | | | | 30,213 | | Lease assignment payable to associated companies | | | 30,529 | | | | 30,529 | | Other | | | 62,624 | | | | 64,746 | | | | | 546,369 | | | | 557,403 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 1,628,764 | | | $ | 1,610,119 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an integral | | part of these balance sheets. | | | | | | | | |
THE TOLEDO EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 992 | | | $ | 17,017 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | | | | Provision for depreciation | | | 7,572 | | | | 9,025 | | Amortization of regulatory assets, net | | | 9,897 | | | | 15,531 | | Purchased power cost recovery reconciliation | | | 2,912 | | | | - | | Deferred rents and lease market valuation liability | | | 6,141 | | | | 6,099 | | Deferred income taxes and investment tax credits, net | | | (2,151 | ) | | | (3,404 | ) | Accrued compensation and retirement benefits | | | 397 | | | | (1,813 | ) | Accrued regulatory obligations | | | 4,450 | | | | - | | Electric service prepayment programs | | | (1,240 | ) | | | (2,670 | ) | Decrease (increase) in operating assets- | | | | | | | | | Receivables | | | (8,395 | ) | | | 45,738 | | Prepayments and other current assets | | | 492 | | | | 181 | | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | 9,018 | | | | (174,243 | ) | Accrued taxes | | | (4,904 | ) | | | 6,840 | | Accrued interest | | | 4,613 | | | | 4,663 | | Other | | | 1,465 | | | | 989 | | Net cash provided from (used for) operating activities | | | 31,259 | | | | (76,047 | ) | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | - | | | | 52,821 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | (181 | ) | | | (9 | ) | Short-term borrowings, net | | | (3,977 | ) | | | - | | Dividend Payments- | | | | | | | | | Common stock | | | (10,000 | ) | | | (15,000 | ) | Other | | | (39 | ) | | | - | | Net cash provided from (used for) financing activities | | | (14,197 | ) | | | 37,812 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (12,233 | ) | | | (19,435 | ) | Loan repayments from (loans to) associated companies, net | | | (21,528 | ) | | | 46,789 | | Redemption of lessor notes | | | 18,358 | | | | 11,989 | | Sales of investment securities held in trusts | | | 44,270 | | | | 3,908 | | Purchases of investment securities held in trusts | | | (44,856 | ) | | | (4,715 | ) | Other | | | (1,072 | ) | | | (110 | ) | Net cash provided from (used for) investing activities | | | (17,061 | ) | | | 38,426 | | | | | | | | | | | Net change in cash and cash equivalents | | | 1 | | | | 191 | | Cash and cash equivalents at beginning of period | | | 14 | | | | 22 | | Cash and cash equivalents at end of period | | $ | 15 | | | $ | 213 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to The Toledo Edison Company are an | | integral part of these statements. | | | | | | | | |
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 provides generation services to 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.
Results of Operations
Net income for the first three months of 2009 decreased to $28 million from $34 million in the same period in 2008. The decrease was primarily due to lower revenues and higher other operating costs, partially offset by lower purchased power costs and reduced amortization of regulatory assets.
Revenues
In the first three months of 2009, revenues decreased by $21 million, or 3%, compared to the same period of 2008. A $31 million increase in retail generation revenues was more than offset by a $47 million decrease in wholesale revenues in the first three months of 2009.
Retail generation revenues from all customer classes increased in the first three months of 2009 compared to the same period of 2008 due to higher unit prices resulting from the BGS auction effective June 1, 2008, partially offset by a decrease in retail generation KWH sales to commercial customers. Sales volume to the commercial sector decreased primarily due to an increase in the number of customers procuring generation from other suppliers.
Wholesale generation revenues decreased $47 million in the first three months of 2009 due to lower market prices and a decrease in sales volume (from NUG purchases) as compared to the first three months of 2008.
Changes in retail generation KWH sales and revenues by customer class in the first three months of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| | | | | | | Residential | | | 0.1 | % | Commercial | | | (7.0 | )% | Industrial | | | 2.9 | % | Net Decrease in Generation Sales | | | (2.7 | )% |
Retail Generation Revenues | | Increase | | | | (In millions) | | Residential | | $ | 30 | | Commercial | | | 1 | | Industrial | | | - | | Increase in Generation Revenues | | $ | 31 | |
Distribution revenues decreased by $1 million in the first three months of 2009 compared to the same period of 2008, reflecting lower KWH deliveries to commercial and industrial customers as a result of weakened economic conditions in JCP&L’s service territory. The decrease in KWH deliveries was partially offset by an increase in composite unit prices.
Changes in distribution KWH deliveries and revenues by customer class in the first three months of 2009 compared to the same period in 2008 are summarized in the following tables:
| | Increase | | Distribution KWH Deliveries | | (Decrease) | | | | | | | | Residential | | | | - | % | Commercial | | | | (2.4 | )% | Industrial | | | | (11.4 | )% | Decrease in Distribution Deliveries | | | | (2.5 | )% |
Distribution Revenues | | Increase (Decrease) | | | | (In millions) | | Residential | | $ | 2 | | Commercial | | | (2 | ) | Industrial | | | (1 | ) | Net Decrease in Distribution Revenues | | $ | (1 | ) |
Expenses
Total expenses decreased by $11 million in the first three months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:
Expenses - Changes | | | Increase (Decrease) | | | | | (In millions) | | Purchased power costs | | | $ | (15 | ) | Other operating costs | | | | 7 | | Provision for depreciation | | | | 2 | | Amortization of regulatory assets | | | | (5 | ) | Net Decrease in Expenses | | | $ | (11 | ) |
Purchased power costs decreased in the first three months of 2009 primarily due to lower KWH purchases to meet the lower demand, partially offset by higher unit prices from the BGS auction effective June 1, 2008. Other operating costs increased in the first three months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs, partially offset by lower contracting and labor expenses. Depreciation expense increased primarily due to an increase in depreciable property since the first quarter of 2008. Amortization of regulatory assets decreased in the first three months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008.
Other Expenses
Other expenses increased by $2 million in the first three months of 2009 compared to the same period in 2008 primarily due to interest expense associated with JCP&L’s $300 million Senior Notes issuance in January 2009.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of other legal proceedings applicable to JCP&L.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to JCP&L.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of Jersey Central Power & Light Company:
We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 760,920 | | | $ | 781,433 | | Excise tax collections | | | 12,731 | | | | 12,795 | | Total revenues | | | 773,651 | | | | 794,228 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power | | | 481,241 | | | | 496,681 | | Other operating costs | | | 85,870 | | | | 78,784 | | Provision for depreciation | | | 25,103 | | | | 23,282 | | Amortization of regulatory assets | | | 86,831 | | | | 91,519 | | General taxes | | | 17,496 | | | | 17,028 | | Total expenses | | | 696,541 | | | | 707,294 | | | | | | | | | | | OPERATING INCOME | | | 77,110 | | | | 86,934 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Miscellaneous income (expense) | | | 805 | | | | (389 | ) | Interest expense | | | (27,868 | ) | | | (24,464 | ) | Capitalized interest | | | 62 | | | | 276 | | Total other expense | | | (27,001 | ) | | | (24,577 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 50,109 | | | | 62,357 | | | | | | | | | | | INCOME TAXES | | | 22,551 | | | | 28,403 | | | | | | | | | | | NET INCOME | | | 27,558 | | | | 33,954 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 4,121 | | | | (3,449 | ) | Unrealized gain on derivative hedges | | | 69 | | | | 69 | | Other comprehensive income (loss) | | | 4,190 | | | | (3,380 | ) | Income tax expense (benefit) related to other comprehensive income | | | 1,430 | | | | (1,470 | ) | Other comprehensive income (loss), net of tax | | | 2,760 | | | | (1,910 | ) | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 30,318 | | | $ | 32,044 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | | are an integral part of these statements. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 4 | | | $ | 66 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,415,000 and $3,230,000 | | | | | | | | | respectively, for uncollectible accounts) | | | 315,084 | | | | 340,485 | | Associated companies | | | 116 | | | | 265 | | Other | | | 35,941 | | | | 37,534 | | Notes receivable - associated companies | | | 91,362 | | | | 16,254 | | Prepaid taxes | | | 4,243 | | | | 10,492 | | Other | | | 21,006 | | | | 18,066 | | | | | 467,756 | | | | 423,162 | | UTILITY PLANT: | | | | | | | | | In service | | | 4,337,711 | | | | 4,307,556 | | Less - Accumulated provision for depreciation | | | 1,562,417 | | | | 1,551,290 | | | | | 2,775,294 | | | | 2,756,266 | | Construction work in progress | | | 69,806 | | | | 77,317 | | | | | 2,845,100 | | | | 2,833,583 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear fuel disposal trust | | | 189,784 | | | | 181,468 | | Nuclear plant decommissioning trusts | | | 136,783 | | | | 143,027 | | Other | | | 2,154 | | | | 2,145 | | | | | 328,721 | | | | 326,640 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 1,810,936 | | | | 1,810,936 | | Regulatory assets | | | 1,162,132 | | | | 1,228,061 | | Other | | | 28,487 | | | | 29,946 | | | | | 3,001,555 | | | | 3,068,943 | | | | $ | 6,643,132 | | | $ | 6,652,328 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 29,465 | | | $ | 29,094 | | Short-term borrowings- | | | | | | | | | Associated companies | | | - | | | | 121,380 | | Accounts payable- | | | | | | | | | Associated companies | | | 22,562 | | | | 12,821 | | Other | | | 158,972 | | | | 198,742 | | Accrued taxes | | | 53,998 | | | | 20,561 | | Accrued interest | | | 30,446 | | | | 9,197 | | Other | | | 129,745 | | | | 133,091 | | | | | 425,188 | | | | 524,886 | | CAPITALIZATION | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, $10 par value, authorized 16,000,000 shares- | | | | | | | | | 13,628,447 shares outstanding | | | 136,284 | | | | 144,216 | | Other paid-in capital | | | 2,502,594 | | | | 2,644,756 | | Accumulated other comprehensive loss | | | (213,778 | ) | | | (216,538 | ) | Retained earnings | | | 121,134 | | | | 156,576 | | Total common stockholder's equity | | | 2,546,234 | | | | 2,729,010 | | Long-term debt and other long-term obligations | | | 1,824,851 | | | | 1,531,840 | | | | | 4,371,085 | | | | 4,260,850 | | NONCURRENT LIABILITIES: | | | | | | | | | Power purchase contract liability | | | 530,538 | | | | 531,686 | | Accumulated deferred income taxes | | | 664,388 | | | | 689,065 | | Nuclear fuel disposal costs | | | 196,260 | | | | 196,235 | | Asset retirement obligations | | | 96,839 | | | | 95,216 | | Retirement benefits | | | 185,265 | | | | 190,182 | | Other | | | 173,569 | | | | 164,208 | | | | | 1,846,859 | | | | 1,866,592 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 6,643,132 | | | $ | 6,652,328 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company are an integral | | part of these balance sheets. | | | | | | | | |
JERSEY CENTRAL POWER & LIGHT COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 27,558 | | | $ | 33,954 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 25,103 | | | | 23,282 | | Amortization of regulatory assets | | | 86,831 | | | | 91,519 | | Deferred purchased power and other costs | | | (28,369 | ) | | | (23,893 | ) | Deferred income taxes and investment tax credits, net | | | (6,408 | ) | | | 723 | | Accrued compensation and retirement benefits | | | (7,481 | ) | | | (15,113 | ) | Cash collateral returned to suppliers | | | (209 | ) | | | (502 | ) | Decrease (increase) in operating assets: | | | | | | | | | Receivables | | | 27,143 | | | | 48,733 | | Materials and supplies | | | - | | | | 255 | | Prepaid taxes | | | 6,249 | | | | (290 | ) | Other current assets | | | (1,457 | ) | | | (1,305 | ) | Increase (decrease) in operating liabilities: | | | | | | | | | Accounts payable | | | (30,029 | ) | | | (14,511 | ) | Accrued taxes | | | 33,114 | | | | 29,844 | | Accrued interest | | | 21,249 | | | | 17,338 | | Other | | | 7,890 | | | | (3,098 | ) | Net cash provided from operating activities | | | 161,184 | | | | 186,936 | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 299,619 | | | | - | | Redemptions and Repayments- | | | | | | | | | Common stock | | | (150,000 | ) | | | - | | Long-term debt | | | (6,402 | ) | | | (5,872 | ) | Short-term borrowings, net | | | (121,380 | ) | | | (48,001 | ) | Dividend Payments- | | | | | | | | | Common stock | | | (63,000 | ) | | | (70,000 | ) | Other | | | (2,152 | ) | | | (68 | ) | Net cash used for financing activities | | | (43,315 | ) | | | (123,941 | ) | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (37,372 | ) | | | (56,047 | ) | Loan repayments from (loans to) associated companies, net | | | (75,108 | ) | | | 18 | | Sales of investment securities held in trusts | | | 115,483 | | | | 56,506 | | Purchases of investment securities held in trusts | | | (120,062 | ) | | | (61,290 | ) | Other | | | (872 | ) | | | (2,236 | ) | Net cash used for investing activities | | | (117,931 | ) | | | (63,049 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | (62 | ) | | | (54 | ) | Cash and cash equivalents at beginning of period | | | 66 | | | | 94 | | Cash and cash equivalents at end of period | | $ | 4 | | | $ | 40 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Jersey Central Power & Light Company | | are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. Met-Ed has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.
Results of Operations
Net income decreased to $17 million in the first quarter of 2009, compared to $22 million in the same period of 2008. The decrease was primarily due to higher purchased power costs and lower deferrals of new regulatory assets, partially offset by higher revenues.
Revenues
Revenues increased by $29 million, or 7.3%, in the first quarter of 2009, compared to the same period of 2008, primarily due to higher distribution throughput revenues and wholesale generation revenues, partially offset by a decrease in retail generation revenues. Wholesale revenues increased by $8 million in the first quarter of 2009, compared to the same period of 2008, due to higher capacity prices for PJM market participants; wholesale KWH sales volume was lower in 2009.
In the first quarter of 2009, retail generation revenues decreased $5 million due to lower KWH sales to the commercial and industrial customer classes, partially offset by higher KWH sales to the residential customer class with a slight increase in composite unit prices in all customer classes. Higher KWH sales in the residential sector were due to increased weather- related usage, reflecting an 8.1% increase in heating degree days in the first quarter of 2009. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory.
Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
| | Increase | | Retail Generation KWH Sales | | (Decrease) | | | | | | | Residential | | | 2.9 | % | Commercial | | | (2.5 | )% | Industrial | | | (12.9 | )% | Net Decrease in Retail Generation Sales | | | (2.9 | )% |
| | Increase | | Retail Generation Revenues | | (Decrease) | | | | (In millions) | | Residential | | $ | 2 | | Commercial | | | (1 | ) | Industrial | | | (6 | ) | Net Decrease in Retail Generation Revenues | | $ | (5 | ) |
In the first quarter of 2009, distribution throughput revenues increased $22 million primarily due to higher transmission rates, resulting from the annual update of Met-Ed’s TSC rider effective June 1, 2008. Decreased deliveries to commercial and industrial customers, reflecting the weakened economy, were partially offset by increased deliveries to residential customers as a result of the weather conditions described above.
Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
| | Increase | | Distribution KWH Deliveries | | (Decrease) | | | | | | | Residential | | | 2.9 | % | Commercial | | | (2.5 | )% | Industrial | | | (12.9 | )% | Net Decrease in Distribution Deliveries | | | (2.9 | )% |
Distribution Revenues | | Increase | | | | (In millions) | | Residential | | $ | 14 | | Commercial | | | 5 | | Industrial | | | 3 | | Increase in Distribution Revenues | | $ | 22 | |
PJM transmission revenues increased by $4 million in the first quarter of 2009 compared to the same period of 2008, primarily due to increased revenues related to Met-Ed’s Auction Revenue Rights and Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $37 million in the first quarter of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | 7 | | Other operating costs | | | (1 | ) | Provision for depreciation | | | 1 | | Deferral of new regulatory assets | | | 30 | | Net Increase in Expenses | | $ | 37 | |
Purchased power costs increased by $7 million in the first quarter of 2009, primarily due to higher composite unit prices partially offset by decreased KWH purchases due to lower generation sales requirements. The deferral of new regulatory assets decreased in the first quarter of 2009 primarily due to decreased transmission cost deferrals reflecting lower PJM transmission service expenses and the increased transmission revenues described above.
Other Expense
Other expense increased in the first quarter of 2009 primarily due to a decrease in interest deferred on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Met-Ed.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Met-Ed.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of Metropolitan Edison Company:
We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiary as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 409,686 | | | $ | 379,608 | | Gross receipts tax collections | | | 19,983 | | | | 20,718 | | Total revenues | | | 429,669 | | | | 400,326 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power from affiliates | | | 100,077 | | | | 83,442 | | Purchased power from non-affiliates | | | 123,911 | | | | 133,540 | | Other operating costs | | | 106,357 | | | | 107,017 | | Provision for depreciation | | | 12,139 | | | | 11,112 | | Amortization of regulatory assets | | | 35,432 | | | | 35,575 | | Deferral of new regulatory assets | | | (7,841 | ) | | | (37,772 | ) | General taxes | | | 21,935 | | | | 21,781 | | Total expenses | | | 392,010 | | | | 354,695 | | | | | | | | | | | OPERATING INCOME | | | 37,659 | | | | 45,631 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Interest income | | | 3,186 | | | | 5,479 | | Miscellaneous income (expense) | | | 856 | | | | (309 | ) | Interest expense | | | (13,359 | ) | | | (11,672 | ) | Capitalized interest | | | 15 | | | | (219 | ) | Total other expense | | | (9,302 | ) | | | (6,721 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 28,357 | | | | 38,910 | | | | | | | | | | | INCOME TAXES | | | 11,735 | | | | 16,675 | | | | | | | | | | | NET INCOME | | | 16,622 | | | | 22,235 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 4,553 | | | | (2,233 | ) | Unrealized gain on derivative hedges | | | 84 | | | | 84 | | Other comprehensive income (loss) | | | 4,637 | | | | (2,149 | ) | Income tax expense (benefit) related to other comprehensive income | | | 1,793 | | | | (970 | ) | Other comprehensive income (loss), net of tax | | | 2,844 | | | | (1,179 | ) | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 19,466 | | | $ | 21,056 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company | | are an integral part of these statements. | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 127 | | | $ | 144 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,867,000 and $3,616,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 161,613 | | | | 159,975 | | Associated companies | | | 27,349 | | | | 17,034 | | Other | | | 17,521 | | | | 19,828 | | Notes receivable from associated companies | | | 229,614 | | | | 11,446 | | Prepaid taxes | | | 57,115 | | | | 6,121 | | Other | | | 5,238 | | | | 1,621 | | | | | 498,577 | | | | 216,169 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,093,792 | | | | 2,065,847 | | Less - Accumulated provision for depreciation | | | 784,064 | | | | 779,692 | | | | | 1,309,728 | | | | 1,286,155 | | Construction work in progress | | | 19,087 | | | | 32,305 | | | | | 1,328,815 | | | | 1,318,460 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 217,476 | | | | 226,139 | | Other | | | 975 | | | | 976 | | | | | 218,451 | | | | 227,115 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 416,499 | | | | 416,499 | | Regulatory assets | | | 489,680 | | | | 412,994 | | Power purchase contract asset | | | 248,762 | | | | 300,141 | | Other | | | 37,231 | | | | 31,031 | | | | | 1,192,172 | | | | 1,160,665 | | | | $ | 3,238,015 | | | $ | 2,922,409 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 128,500 | | | $ | 28,500 | | Short-term borrowings- | | | | | | | | | Associated companies | | | - | | | | 15,003 | | Other | | | 250,000 | | | | 250,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 29,764 | | | | 28,707 | | Other | | | 46,216 | | | | 55,330 | | Accrued taxes | | | 8,489 | | | | 16,238 | | Accrued interest | | | 11,557 | | | | 6,755 | | Other | | | 29,506 | | | | 30,647 | | | | | 504,032 | | | | 431,180 | | CAPITALIZATION: | | | | | | | | | Common stockholder's equity- | | | | | | | | | Common stock, without par value, authorized 900,000 shares- | | | | | | | | | 859,500 shares outstanding | | | 1,196,090 | | | | 1,196,172 | | Accumulated other comprehensive loss | | | (138,140 | ) | | | (140,984 | ) | Accumulated deficit | | | (34,502 | ) | | | (51,124 | ) | Total common stockholder's equity | | | 1,023,448 | | | | 1,004,064 | | Long-term debt and other long-term obligations | | | 713,782 | | | | 513,752 | | | | | 1,737,230 | | | | 1,517,816 | | NONCURRENT LIABILITIES: | | | | | | | | | Accumulated deferred income taxes | | | 390,448 | | | | 387,757 | | Accumulated deferred investment tax credits | | | 7,653 | | | | 7,767 | | Nuclear fuel disposal costs | | | 44,334 | | | | 44,328 | | Asset retirement obligations | | | 171,561 | | | | 170,999 | | Retirement benefits | | | 144,459 | | | | 145,218 | | Power purchase contract liability | | | 172,520 | | | | 150,324 | | Other | | | 65,778 | | | | 67,020 | | | | | 996,753 | | | | 973,413 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 3,238,015 | | | $ | 2,922,409 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are an integral | | part of these balance sheets. | | | | | | | | |
METROPOLITAN EDISON COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 16,622 | | | $ | 22,235 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 12,139 | | | | 11,112 | | Amortization of regulatory assets | | | 35,432 | | | | 35,575 | | Deferred costs recoverable as regulatory assets | | | (19,633 | ) | | | (10,628 | ) | Deferral of new regulatory assets | | | (7,841 | ) | | | (37,772 | ) | Deferred income taxes and investment tax credits, net | | | 4,657 | | | | 17,307 | | Accrued compensation and retirement benefits | | | 1,029 | | | | (9,655 | ) | Cash collateral to suppliers | | | (9,500 | ) | | | - | | Increase in operating assets- | | | | | | | | | Receivables | | | (9,860 | ) | | | (30,863 | ) | Prepayments and other current assets | | | (50,422 | ) | | | (41,088 | ) | Increase (decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (8,058 | ) | | | (14,196 | ) | Accrued taxes | | | (7,749 | ) | | | (14,519 | ) | Accrued interest | | | 4,803 | | | | 281 | | Other | | | 2,460 | | | | 3,892 | | Net cash used for operating activities | | | (35,921 | ) | | | (68,319 | ) | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Long-term debt | | | 300,000 | | | | - | | Short-term borrowings, net | | | - | | | | 131,743 | | Redemptions and Repayments- | | | | | | | | | Long-term debt | | | - | | | | (28,500 | ) | Short-term borrowings, net | | | (15,003 | ) | | | - | | Other | | | (2,150 | ) | | | (15 | ) | Net cash provided from financing activities | | | 282,847 | | | | 103,228 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (25,922 | ) | | | (31,296 | ) | Sales of investment securities held in trusts | | | 27,800 | | | | 40,513 | | Purchases of investment securities held in trusts | | | (29,821 | ) | | | (43,391 | ) | Loans to associated companies, net | | | (218,168 | ) | | | (254 | ) | Other | | | (832 | ) | | | (484 | ) | Net cash used for investing activities | | | (246,943 | ) | | | (34,912 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | (17 | ) | | | (3 | ) | Cash and cash equivalents at beginning of period | | | 144 | | | | 135 | | Cash and cash equivalents at end of period | | $ | 127 | | | $ | 132 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Metropolitan Edison Company are | | an integral part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. Penelec has a partial requirements wholesale power sales agreement with FES, to supply a portion of each of its default service obligations at fixed prices through 2009. This sales agreement is renewed annually unless cancelled by either party with at least a sixty day written notice prior to the end of the calendar year.
Results of Operations
Net income decreased to $19 million in the first quarter of 2009, compared to $21 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by an increase in the deferral of new regulatory assets.
Revenues
Revenues decreased by $7 million, or 1.7%, in the first quarter of 2009 as compared to the same period of 2008, primarily due to lower retail generation revenues and PJM transmission revenues, partially offset by increased distribution throughput revenues and wholesale generation revenues. Wholesale generation revenues increased $7 million in the first quarter of 2009 as compared to the same period of 2008, primarily reflecting higher PJM capacity prices.
In the first quarter of 2009, retail generation revenues decreased $8 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions, partially offset by a slight increase in KWH sales to the residential customer class.
Changes in retail generation sales and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase
(Decrease)
| | | | | | Residential | | | 0.4 | % | Commercial | | | (3.2 | ) % | Industrial | | | (13.9 | ) % | Net Decrease in Retail Generation Sales | | | (4.9 | ) % |
Retail Generation Revenues | | Decrease | | | | (In millions) | | Residential | | $ | - | | Commercial | | | (2 | ) | Industrial | | | (6 | ) | Decrease in Retail Generation Revenues | | $ | (8 | ) |
Revenues from distribution throughput increased $5 million in the first quarter of 2009 compared to the same period of 2008, primarily due to an increase in transmission rates, resulting from the annual update of Penelec’s TSC rider effective June 1, 2008, and a slight increase in usage in the residential sector. Partially offsetting this increase was lower usage in the commercial and industrial sectors, reflecting economic conditions in Penelec’s service territory.
Changes in distribution KWH deliveries and revenues in the first quarter of 2009 compared to the same period of 2008 are summarized in the following tables:
Distribution KWH Deliveries | | Increase
(Decrease)
| | | | | | Residential | | | 0.4 | % | Commercial | | | (3.2 | ) % | Industrial | | | (12.0 | ) % | Net Decrease in Distribution Deliveries | | | (4.6 | ) % |
Distribution Revenues | | Increase | | | | (In millions) | | Residential | | $ | 4 | | Commercial | | | 1 | | Industrial | | | - | | Increase in Distribution Revenues | | $ | 5 | |
PJM transmission revenues decreased by $13 million in the first quarter of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $5 million in the first quarter of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | 2 | | Other operating costs | | | 6 | | Provision for depreciation | | | 2 | | Deferral of new regulatory assets | | | (4 | ) | General taxes | | | (1 | ) | Net Increase in Expenses | | $ | 5 | |
Purchased power costs increased by $2 million, or 0.9%, in the first quarter of 2009 compared to the same period of 2008, primarily due to increased composite unit prices, partially offset by reduced volume as a result of lower KWH sales requirements. Other operating costs increased by $6 million in the first quarter of 2009 primarily due to higher employee benefit expenses. Depreciation expense increased $2 million in the first quarter of 2009 primarily due to an increase in depreciable property in service since the first quarter of 2008. The deferral of new regulatory assets increased $4 million in the first quarter of 2009 primarily due to an increase in transmission cost deferrals as a result of increased net congestion costs.
Other Income
In the first quarter of 2009, other income increased primarily due to lower interest expense on reduced borrowings from the regulated money pool.
Legal Proceedings
See the “Regulatory Matters,” “Environmental Matters” and “Other Legal Proceedings” sections within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of legal proceedings applicable to Penelec.
New Accounting Standards and Interpretations
See the “New Accounting Standards and Interpretations” section within the Combined Management’s Discussion and Analysis of Registrant Subsidiaries for discussion of new accounting standards and interpretations applicable to Penelec.
Report of Independent Registered Public Accounting Firm
To the Stockholder and Board of Directors of Pennsylvania Electric Company:
We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of March 31,September 30, 2009 and the related consolidated statements of income and comprehensive income and cash flows for each of the three-month and nine-month periods ended March 31,September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.
We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.
Based on our review, we are not aware of any material modifications that should be made to the accompanying consolidated interim financial statements for them to be in conformity with accounting principles generally accepted in the United States of America.
We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived. | PricewaterhouseCoopers LLP Cleveland, Ohio May 7,November 6, 2009
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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
Net income in the third quarter of 2009 was $234 million, or basic and diluted earnings of $0.77 per share of common stock, compared with net income of $471 million, or basic earnings of $1.55 per share of common stock ($1.54 diluted) in the third quarter of 2008. Results in the third quarter of 2009 include a loss of $0.30 per share resulting from the redemption of $1.2 billion of our 6.45% notes, partially offset by $0.25 per share of investment income resulting primarily from the sale of securities held in our nuclear decommissioning trust. Net income in the first nine months of 2009 was $768 million or basic earnings of $2.52 per share of common stock ($2.51 diluted), compared with net income of $1.01 billion, or basic earnings of $3.32 per share of common stock ($3.29 diluted) in the first nine months of 2008.
Change in Basic Earnings Per Share From Prior Year Periods | | Three Months Ended September 30 | | Nine Months Ended September 30 | | | | | | | | | | Basic Earnings Per Share – 2008 | | | $ | 1.55 | | | $ | 3.32 | | Gain on non-core asset sales | | | - | | | 0.46 | | Litigation settlement – 2008 | | | - | | | (0.03 | ) | Debt redemption premium - 2009 | | | (0.30 | ) | | (0.30 | ) | Organizational restructuring costs – 2009 | | | (0.07 | ) | | (0.14 | ) | Regulatory charges – 2009 | | | - | | | (0.55 | ) | Investment Income | | | 0.17 | | | 0.12 | | Trust securities impairments | | | 0.08 | | | 0.08 | | Income tax adjustments | | | (0.12 | ) | | (0.09 | ) | Revenues (excluding asset sales) | | | (1.04 | ) | | (1.29 | ) | Fuel and purchased power | | | 0.10 | | | 0.03 | | Transmission costs | | | 0.30 | | | 0.56 | | Amortization of regulatory assets, net | | | (0.06 | ) | | (0.03 | ) | Other expenses | | | 0.16 | | | 0.38 | | Basic Earnings Per Share – 2009 | | | $ | 0.77 | | | $ | 2.52 | |
Regulatory Matters
Ohio Regulatory Update
On August 6, 2009, the PUCO withdrew proposed rules it had forwarded to the Joint Committee on Agency Rules Review regarding implementation of the alternative energy portfolio standards created by SB221, incorporating energy efficiency requirements, long-term forecasting and planning for greenhouse gas reporting and carbon dioxide control. The rules remain under consideration. On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio companies' customers. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency application submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.
On August 19, 2009, the PUCO approved FirstEnergy’s proposal to accelerate the recovery of deferred costs. The principal amount plus carrying charges through August 31, 2009, for these deferrals was $305.1 million. Accelerated recovery began September 1, 2009, and will be collected in the 18 non-summer months through May 31, 2011.
On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP In August and October 2009, the Ohio Companies conducted RFPs to Secure Renewable Energy Credits (RECs). The RFPs include solar and other renewable energy RECs, including those generated in Ohio. The RFCs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010 and 2011. Pennsylvania Regulatory Update
Met-Ed and Penelec Default Service Plan Settlements
On August 12, 2009, Met-Ed and Penelec filed a settlement agreement with the PPUC for the generation procurement plan covering the period January 1, 2011, through May 31, 2013, reflecting the settlement on all but two issues. The settlement plan is designed to provide adequate and reliable service as required by Pennsylvania law through a prudent mix of long-term, short-term and spot-market generation supply as required by Act 129. The settlement plan proposes a staggered procurement schedule, which varies by customer class. If approved, generation procurement would begin in January 2010.
On September 2, 2009, the ALJ issued a Recommended Decision (RD) and adopted the Companies’ positions on two reserved issues. Exceptions to the ALJ RD were filed on September 22, 2009, with reply exceptions being filed on October 2, 2009. The PPUC's final decision is expected in November 2009.
By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies will file reply comments on October 26, 2009.
Pennsylvania Smart Meter Plan
On August 14, 2009, Penn, Met-Ed and Penelec (the Companies) filed a Smart Meter Technology Procurement and Installation Plan with the PPUC as required by Act 129. The plan includes proposed tariff riders to recover the costs of implementation of the plan and an assessment period of twenty-four months to evaluate needs, select technology, secure vendors, train personnel, install and support test equipment and establish a detailed meter deployment schedule consistent with the requirements of Act 129. At the end of the assessment period, the Companies will submit to the PPUC a supplement to the plan to set forth in detail the Companies’ proposal for the full scale deployment of smart meters. The Companies are asking the PPUC to approve, as part the plan, both the proposed recovery mechanism and the recovery of costs of the assessment period, currently estimated at $29.5 million, through such mechanism.
New Jersey Solar Renewable Energy Certificates
JCP&L, in collaboration with another New Jersey electric utility, Atlantic City Electric Company (ACE), announced a RFP to secure Solar Renewable Energy Certificates (SREC) as part of the NJBPU's effort to support new solar energy projects. The RFP process was established to help create long-term agreements to purchase and sell SRECs to provide a stable basis for financing new solar generation projects in the companies' service areas. A total of 61 MW of solar generating capacity - 19 for ACE and 42 for JCP&L - will be solicited to help meet New Jersey Renewable Portfolio Standards. The first solicitation was conducted in August; subsequent solicitations will occur over the next three years. The costs of this program are expected to be fully recoverable through a per KWH rate approved by the NJBPU and applied to all customers.
Operational Matters
Fremont Energy Center
On September 22, 2009, FirstEnergy announced it expects to complete construction of the Fremont Energy Center by the end of 2010. Originally acquired by FGCO in January 2008, the Fremont Energy Center 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. With the accelerated construction schedule, FES estimates the remaining cost to complete the project to be $180 million.
Nuclear Outage
On October 12, 2009, NGC's Beaver Valley Nuclear Power Station Unit 2, located in Shippingport, Pennsylvania began a scheduled refueling and maintenance outage. During the outage, 60 of the 157 fuel assemblies will be exchanged and safety inspections conducted. In addition, numerous improvement projects will be completed to ensure continued safe and reliable operations.
PJM Regional Transmission Organization (RTO) Integration
As described in the “FERC Matters” section of this document, on August 17, 2009, FirstEnergy filed an application with the FERC to consolidate its transmission assets and operations into PJM. Currently FirstEnergy's transmission assets and operations are divided between PJM and MISO. The consolidation would move the transmission assets that are part of FirstEnergy's ATSI subsidiary and are located within the footprint of FirstEnergy's Ohio utilities and Pennsylvania Power - into PJM. If approved, the consolidation would provide customers with the benefits of a more fully developed retail choice market, and FirstEnergy and its Utilities with the operating efficiencies of a single RTO - with one set of rules, procedures and protocols. To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.
FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.
On September 4, 2009, the PUCO opened a case to take comments from Ohio stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009, and reply comments on October 13, 2009, and attended a public hearing on September 15, 2009, to respond to questions regarding the RTO consolidation.
Several parties have intervened in the regulatory dockets at the FERC and the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.
Voluntary Enhanced Retirement Option
FirstEnergy’s VERO enrollment period concluded September 16, 2009. The VERO was accepted by a total 397 non-represented employees and 318 union employees.
FirstEnergy Solutions Offers Economic Support Program
In September 2009, FES introduced Powering Our Communities, an innovative program that offers economic support to communities in the OE, CEI and TE service areas that purchase discounted electric generation supply from FES through government aggregation programs. The program will provide up-front grants to local Ohio communities and long-term electric generation price savings.
Smart Grid Proposal
On August 6, 2009, FirstEnergy filed an application for economic stimulus funding with the U.S. Department of Energy under the American Recovery and Reinvestment Act that proposed investing $114 million on smart grid technologies to improve the reliability and interactivity of its electric distribution infrastructure in its three-state service area. The application requested $57 million, which represents half of the funding needed for targeted projects in communities served by the Utilities. On October 27, 2009, FirstEnergy received notice from the Department of Energy that its application was selected for award negotiations. However, no assurance can be given that we will receive any such award.
Financial Matters
Rating Agency Update
On August 3, 2009, Moody's Investor Service upgraded the senior secured debt ratings of FirstEnergy’s seven regulated utilities as follows: CEI and TE were each upgraded to Baa1 from Baa2, and JCP&L, Met-Ed, OE, Penelec and Penn were each upgraded to A3 from Baa1.
Financing Activities
On August 7, 2009, FES issued 5, 12 and 30-year unsecured senior notes totaling $1.5 billion. The notes bear interest at an annual rate of 4.80%, 6.05% and 6.80%, respectively. Proceeds received from the issuance of the notes were used to pay down borrowings under the $2.75 billion revolving credit facility that FES shares with FirstEnergy and certain other subsidiaries, which made borrowing capacity available to FirstEnergy under the facility to fund a cash tender offer for $1.2 billion of its 6.45% notes, Series B, due 2011. FirstEnergy announced the tender offer on August 4, 2009 and completed it on September 1, 2009. $250 million of the 2011 notes remain outstanding.
On August 14, 2009, $177 million of PCRBs were issued and sold on behalf of FGCO relating to air quality compliance expenditures at the Sammis Plant. The PCRBs bear interest at an annual rate of 5.7% and mature on August 1, 2020.
On August 18, 2009, CEI issued $300 million of FMB that bear interest at an annual rate of 5.5% and mature on August 15, 2024. A portion of the proceeds will be used to replace $150 million of CEI’s 7.43% Series D Secured Notes that mature on November 1, 2009. The remaining proceeds were used to repay a portion of CEI’s short-term borrowings.
On September 2, 2009, the Utilities and ATSI voluntarily contributed $500 million to the pension plan. On September 30, 2009, Penelec issued $500 million of unsecured notes, of which $250 million mature in 2020 and $250 million mature in 2038. The 2020 notes and 2038 notes bear interest at an annual rate of 5.20% and 6.15%, respectively.
On October 1, 2009, FGCO and NGC purchased $52.1 million and $29.6 million of PCRBs subject to mandatory purchase. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in the near future.
FIRSTENERGY'S BUSINESS
FirstEnergy is a diversified energy company headquartered in Akron, Ohio, that operates primarily through three core business segments (see Results of Operations).
· | Energy Delivery Services transmits and distributes electricity through FirstEnergy's eight utility operating companies, serving 4.5 million customers within 36,100 square miles of Ohio, Pennsylvania and New Jersey and purchases power for its PLR and default service requirements. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy's service areas and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service). |
· | Competitive Energy Services supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the PLR and default service requirements of FirstEnergy's Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Maryland, Michigan and Illinois. This business segment owns or leases and operates 19 generating facilities with a net demonstrated capacity of 13,710 MW and also purchases electricity to meet sales obligations. The segment's net income is derived primarily from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment's customers. |
· | Ohio Transitional Generation Services supplies the electric power needs of non-shopping customers under the default service requirements of FirstEnergy's Ohio Companies. The segment's net income is derived primarily from electric generation sales revenues (including transmission) less the cost of power purchased through the Ohio Companies' CBP and transmission and ancillary costs charged by MISO to deliver energy to retail customers. |
RESULTS OF OPERATIONS
The financial results discussed below include revenues and expenses from transactions among FirstEnergy's business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Earnings by major business segment were as follows:
| | Three Months Ended September 30 | | Nine Months Ended September 30 | | | | | | Increase | | | | Increase | | | | 2009 | | 2008 | | (Decrease) | | 2009 | | 2008 | | (Decrease) | | | | (In millions, except per share data) | | Earnings By Business Segment: | | | | | | | | | | | | | | Energy delivery services | | $ | 139 | | $ | 283 | | $ | (144 | ) | $ | 230 | | $ | 655 | | $ | (425 | ) | Competitive energy services | | | 183 | | | 164 | | | 19 | | | 614 | | | 317 | | | 297 | | Ohio transitional generation services | | | 9 | | | 19 | | | (10 | ) | | 55 | | | 62 | | | (7 | ) | Other and reconciling adjustments* | | | (101 | ) | | 5 | | | (106 | ) | | (145 | ) | | (24 | ) | | (121 | ) | Total | | $ | 230 | | $ | 471 | | $ | (241 | ) | $ | 754 | | $ | 1,010 | | $ | (256 | ) | | | | | | | | | | | | | | | | | | | | | Basic Earnings Per Share | | $ | .77 | | $ | 1.55 | | $ | (.78 | ) | $ | 2.52 | | $ | 3.32 | | $ | (.80 | ) | Diluted Earnings Per Share | | $ | .77 | | $ | 1.54 | | $ | (.77 | ) | $ | 2.51 | | $ | 3.29 | | $ | (.78 | ) | | | | | | | | | | | | | | | | | | | | | * Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions. | |
Summary of Results of Operations – Third Quarter 2009 Compared with Third Quarter 2008
Financial results for FirstEnergy's major business segments in the third quarter of 2009 and 2008 were as follows:
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | Third Quarter 2009 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 2,067 | | | $ | 444 | | | $ | 737 | | | $ | - | | | $ | 3,248 | | Other | | | 136 | | | | 46 | | | | 2 | | | | (24 | ) | | | 160 | | Internal | | | - | | | | 617 | | | | - | | | | (617 | ) | | | - | | Total Revenues | | | 2,203 | | | | 1,107 | | | | 739 | | | | (641 | ) | | | 3,408 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | - | | | | 302 | | | | - | | | | - | | | | 302 | | Purchased power | | | 1,011 | | | | 205 | | | | 714 | | | | (617 | ) | | | 1,313 | | Other operating expenses | | | 373 | | | | 331 | | | | (9 | ) | | | (30 | ) | | | 665 | | Provision for depreciation | | | 112 | | | | 69 | | | | - | | | | 7 | | | | 188 | | Amortization of regulatory assets | | | 244 | | | | - | | | | 17 | | | | - | | | | 261 | | Deferral of new regulatory assets | | | - | | | | - | | | | - | | | | - | | | | - | | General taxes | | | 160 | | | | 27 | | | | 2 | | | | 3 | | | | 192 | | Total Expenses | | | 1,900 | | | | 934 | | | | 724 | | | | (637 | ) | | | 2,921 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 303 | | | | 173 | | | | 15 | | | | (4 | ) | | | 487 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 46 | | | | 159 | | | | - | | | | (14 | ) | | | 191 | | Interest expense | | | (118 | ) | | | (46 | ) | | | - | | | | (191 | ) | | | (355 | ) | Capitalized interest | | | 1 | | | | 18 | | | | - | | | | 16 | | | | 35 | | Total Other Expense | | | (71 | ) | | | 131 | | | | - | | | | (189 | ) | | | (129 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 232 | | | | 304 | | | | 15 | | | | (193 | ) | | | 358 | | Income taxes | | | 93 | | | | 121 | | | | 6 | | | | (92 | ) | | | 128 | | Net Income | | | 139 | | | | 183 | | | | 9 | | | | (101 | ) | | | 230 | | Less: Noncontrolling interest income (loss) | | | - | | | | - | | | | - | | | | (4 | ) | | | (4 | ) | Earnings available to FirstEnergy Corp. | | $ | 139 | | | $ | 183 | | | $ | 9 | | | $ | (97 | ) | | $ | 234 | |
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | Third Quarter 2008 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 2,487 | | | $ | 381 | | | $ | 781 | | | $ | - | | | $ | 3,649 | | Other | | | 170 | | | | 79 | | | | 32 | | | | (26 | ) | | | 255 | | Internal | | | - | | | | 786 | | | | - | | | | (786 | ) | | | - | | Total Revenues | | | 2,657 | | | | 1,246 | | | | 813 | | | | (812 | ) | | | 3,904 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | - | | | | 356 | | | | - | | | | - | | | | 356 | | Purchased power | | | 1,248 | | | | 221 | | | | 623 | | | | (786 | ) | | | 1,306 | | Other operating expenses | | | 430 | | | | 285 | | | | 110 | | | | (31 | ) | | | 794 | | Provision for depreciation | | | 99 | | | | 67 | | | | - | | | | 2 | | | | 168 | | Amortization of regulatory assets, net | | | 263 | | | | - | | | | 28 | | | | - | | | | 291 | | Deferral of new regulatory assets | | | (76 | ) | | | - | | | | 18 | | | | - | | | | (58 | ) | General taxes | | | 169 | | | | 26 | | | | 1 | | | | 5 | | | | 201 | | Total Expenses | | | 2,133 | | | | 955 | | | | 780 | | | | (810 | ) | | | 3,058 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 524 | | | | 291 | | | | 33 | | | | (2 | ) | | | 846 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 48 | | | | 13 | | | | 1 | | | | (22 | ) | | | 40 | | Interest expense | | | (102 | ) | | | (44 | ) | | | (1 | ) | | | (45 | ) | | | (192 | ) | Capitalized interest | | | 1 | | | | 13 | | | | - | | | | 1 | | | | 15 | | Total Other Expense | | | (53 | ) | | | (18 | ) | | | - | | | | (66 | ) | | | (137 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 471 | | | | 273 | | | | 33 | | | | (68 | ) | | | 709 | | Income taxes | | | 188 | | | | 109 | | | | 14 | | | | (73 | ) | | | 238 | | Net Income | | | 283 | | | | 164 | | | | 19 | | | | 5 | | | | 471 | | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | - | | | | - | | Earnings available to FirstEnergy Corp. | | $ | 283 | | | $ | 164 | | | $ | 19 | | | $ | 5 | | | $ | 471 | | | | | | | | | | | | | | | | | | | | | | | Changes Between Third Quarter 2009 and | | | | | | | | | | | | | | | | | | | | | Third Quarter 2008 Financial Results | | | | | | | | | | | | | | | | | | | | | Increase (Decrease) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | | | Electric | | $ | (420 | ) | | $ | 63 | | | $ | (44 | ) | | $ | - | | | $ | (401 | ) | Other | | | (34 | ) | | | (33 | ) | | | (30 | ) | | | 2 | | | | (95 | ) | Internal | | | - | | | | (169 | ) | | | - | | | | 169 | | | | - | | Total Revenues | | | (454 | ) | | | (139 | ) | | | (74 | ) | | | 171 | | | | (496 | ) | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | - | | | | (54 | ) | | | - | | | | - | | | | (54 | ) | Purchased power | | | (237 | ) | | | (16 | ) | | | 91 | | | | 169 | | | | 7 | | Other operating expenses | | | (57 | ) | | | 46 | | | | (119 | ) | | | 1 | | | | (129 | ) | Provision for depreciation | | | 13 | | | | 2 | | | | - | | | | 5 | | | | 20 | | Amortization of regulatory assets | | | (19 | ) | | | - | | | | (11 | ) | | | - | | | | (30 | ) | Deferral of new regulatory assets | | | 76 | | | | - | | | | (18 | ) | | | - | | | | 58 | | General taxes | | | (9 | ) | | | 1 | | | | 1 | | | | (2 | ) | | | (9 | ) | Total Expenses | | | (233 | ) | | | (21 | ) | | | (56 | ) | | | 173 | | | | (137 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | (221 | ) | | | (118 | ) | | | (18 | ) | | | (2 | ) | | | (359 | ) | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | (2 | ) | | | 146 | | | | (1 | ) | | | 8 | | | | 151 | | Interest expense | | | (16 | ) | | | (2 | ) | | | 1 | | | | (146 | ) | | | (163 | ) | Capitalized interest | | | - | | | | 5 | | | | - | | | | 15 | | | | 20 | | Total Other Expense | | | (18 | ) | | | 149 | | | | - | | | | (123 | ) | | | 8 | | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | (239 | ) | | | 31 | | | | (18 | ) | | | (125 | ) | | | (351 | ) | Income taxes | | | (95 | ) | | | 12 | | | | (8 | ) | | | (19 | ) | | | (110 | ) | Net Income | | | (144 | ) | | | 19 | | | | (10 | ) | | | (106 | ) | | | (241 | ) | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | (4 | ) | | | (4 | ) | Earnings available to FirstEnergy Corp. | | $ | (144 | ) | | $ | 19 | | | $ | (10 | ) | | $ | (102 | ) | | $ | (237 | ) |
Energy Delivery Services – Third Quarter 2009 Compared with Third Quarter 2008
Net income decreased $144 million to $139 million in the third quarter of 2009 compared to $283 million in the third quarter of 2008, primarily due to lower revenues and decreased deferrals of new regulatory assets, partially offset by lower purchased power and other operating expenses.
Revenues –
The decrease in total revenues resulted from the following sources:
| | Three Months | | | | | | | Ended September 30 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | | | $ | 915 | | $ | 1,100 | | $ | (185 | ) | | | | | | | | | | | | | | | 825 | | | 986 | | | (161 | ) | | | | 195 | | | 286 | | | (91 | ) | | | | 1,020 | | | 1,272 | | | (252 | ) | | | | 221 | | | 241 | | | (20 | ) | | | | 47 | | | 44 | | | 3 | | | | $ | 2,203 | | $ | 2,657 | | $ | (454 | ) |
The decrease in distribution deliveries by customer class is summarized in the following table:
Electric Distribution KWH Deliveries | | | | | | | (8.1) | | | | | (6.2) | | | | | (15.7) | | Total Distribution KWH Deliveries | | | (9.8) | |
Lower deliveries to residential customers reflected decreased weather-related usage in the third quarter of 2009, as cooling degree days decreased by 14% from the same period in 2008. The decrease in distribution deliveries to commercial and industrial customers was primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined due to major automotive customers (10.1%) and steel customers (42.3%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs, and the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).
The following table summarizes the price and volume factors contributing to the $252 million decrease in generation revenues in the third quarter of 2009 compared to the third quarter of 2008:
Sources of Change in Generation Revenues | | (Decrease) | | | | (In millions) | | Retail: | | | | | Effect of 12% decrease in sales volumes | | $ | (113) | | Change in prices | | | (48) | | | | | (161) | | Wholesale: | | | | | Effect of 18% decrease in sales volumes | | | (51) | | Change in prices | | | (40) | | | | | (91) | | Decrease in Generation Revenues | | $ | (252) | |
The decrease in retail generation sales volumes was primarily due to weakened economic conditions and the lower weather-related usage described above. The decrease in retail generation prices during the third quarter of 2009 reflected lower composite generation rates for JCP&L resulting from the New Jersey BGS auction and for Penn under its RFP process. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot prices for PJM market participants.
Transmission revenues decreased $20 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed resulting from the annual update to its TSC rider in June 2009. Met-Ed and Penelec defer the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).
Expenses –
Total expenses decreased by $233 million due to the net impact of the following:
| · | Purchased power costs were $237 million lower in the third quarter of 2009 due to lower volume requirements and an increase in the amount of NUG costs deferred. JCP&L, Met-Ed and Penelec are permitted to defer for future collection from customers the amounts by which costs incurred under NUG agreements exceed amounts collected through rates. The following table summarizes the sources of changes in purchased power costs: |
Source of Change in Purchased Power | | Increase (Decrease) | | | | (In millions) | | Purchases from non-affiliates: | | | | | Change due to increased unit costs | | $ | 38 | | Change due to decreased volumes | | | (209 | ) | | | | (171 | ) | Purchases from FES: | | | | | Change due to decreased unit costs | | | (7 | ) | Change due to increased volumes | | | 19 | | | | | 12 | | | | | | | Increase in NUG costs deferred | | | (78 | ) | Net Decrease in Purchased Power Costs | | $ | (237 | ) |
· PJM transmission expenses were lower by $83 million resulting from reduced volumes and congestion costs.
· Contractor and material costs decreased $9 million due primarily to reduced maintenance activities as more work was devoted to capital projects.
· Organizational restructuring charges of $15 million were partially offset by lower labor expenses of $11 million.
· Employee benefits increased $37 million as a result of higher pension costs.
· Storm-related costs were $6 million lower than in the third quarter of 2008. ·Amortization of regulatory assets decreased $19 million due primarily to the cessation of transition cost amortization for OE and TE, partially offset by higher PJM transmission cost amortization in the third quarter of 2009.
· The deferral of new regulatory assets decreased by $76 million in the third quarter of 2009 principally due to the absence of PJM transmission cost deferrals in Pennsylvania and RCP distribution cost deferrals by the Ohio Companies.
· Depreciation expense increased $13 million due to property additions since the third quarter of 2008.
· General taxes decreased $9 million primarily due to lower gross receipts and excise taxes.
Other Expense –
Other expense increased $18 million in the third quarter of 2009 compared to the third quarter of 2008 due to higher interest expense of $16 million, reflecting $300 million of senior notes issuances by each of JCP&L and Met-Ed in January 2009, $300 million of senior notes by TE in April 2009, and $300 million of FMBs by CEI in August 2009, partially offset by lower investment income of $2 million (reduced loan balances to the regulated money pool).
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | REVENUES: | | | | | | | Electric sales | | $ | 371,293 | | | $ | 376,028 | | Gross receipts tax collections | | | 17,292 | | | | 19,464 | | Total revenues | | | 388,585 | | | | 395,492 | | | | | | | | | | | EXPENSES: | | | | | | | | | Purchased power from affiliates | | | 96,081 | | | | 83,464 | | Purchased power from non-affiliates | | | 127,166 | | | | 137,770 | | Other operating costs | | | 77,289 | | | | 71,077 | | Provision for depreciation | | | 14,455 | | | | 12,516 | | Amortization of regulatory assets | | | 16,141 | | | | 16,346 | | Deferral of new regulatory assets | | | (7,365 | ) | | | (3,526 | ) | General taxes | | | 20,593 | | | | 21,855 | | Total expenses | | | 344,360 | | | | 339,502 | | | | | | | | | | | OPERATING INCOME | | | 44,225 | | | | 55,990 | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | Miscellaneous income (expense) | | | 798 | | | | (191 | ) | Interest expense | | | (13,233 | ) | | | (15,322 | ) | Capitalized interest | | | 22 | | | | (806 | ) | Total other expense | | | (12,413 | ) | | | (16,319 | ) | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 31,812 | | | | 39,671 | | | | | | | | | | | INCOME TAXES | | | 13,122 | | | | 18,279 | | | | | | | | | | | NET INCOME | | | 18,690 | | | | 21,392 | | | | | | | | | | | OTHER COMPREHENSIVE INCOME (LOSS): | | | | | | | | | Pension and other postretirement benefits | | | 2,955 | | | | (3,473 | ) | Unrealized gain on derivative hedges | | | 16 | | | | 16 | | Change in unrealized gain on available-for-sale securities | | | (22 | ) | | | 11 | | Other comprehensive income (loss) | | | 2,949 | | | | (3,446 | ) | Income tax expense (benefit) related to other comprehensive income | | | 1,055 | | | | (1,506 | ) | Other comprehensive income (loss), net of tax | | | 1,894 | | | | (1,940 | ) | | | | | | | | | | TOTAL COMPREHENSIVE INCOME | | $ | 20,584 | | | $ | 19,452 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company | | are an integral part of these statements. | | | | | | | | |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED BALANCE SHEETS | | (Unaudited) | | | | March 31, | | | December 31, | | | | 2009 | | | 2008 | | | | (In thousands) | | ASSETS | | | | | | | CURRENT ASSETS: | | | | | | | Cash and cash equivalents | | $ | 13 | | | $ | 23 | | Receivables- | | | | | | | | | Customers (less accumulated provisions of $3,285,000 and $3,121,000, | | | | | | | | | respectively, for uncollectible accounts) | | | 140,783 | | | | 146,831 | | Associated companies | | | 80,387 | | | | 65,610 | | Other | | | 19,493 | | | | 26,766 | | Notes receivable from associated companies | | | 15,198 | | | | 14,833 | | Prepaid taxes | | | 66,392 | | | | 16,310 | | Other | | | 1,142 | | | | 1,517 | | | | | 323,408 | | | | 271,890 | | UTILITY PLANT: | | | | | | | | | In service | | | 2,345,475 | | | | 2,324,879 | | Less - Accumulated provision for depreciation | | | 873,677 | | | | 868,639 | | | | | 1,471,798 | | | | 1,456,240 | | Construction work in progress | | | 25,042 | | | | 25,146 | | | | | 1,496,840 | | | | 1,481,386 | | OTHER PROPERTY AND INVESTMENTS: | | | | | | | | | Nuclear plant decommissioning trusts | | | 113,265 | | | | 115,292 | | Non-utility generation trusts | | | 117,899 | | | | 116,687 | | Other | | | 289 | | | | 293 | | | | | 231,453 | | | | 232,272 | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | Goodwill | | | 768,628 | | | | 768,628 | | Power purchase contract asset | | | 78,226 | | | | 119,748 | | Other | | | 15,308 | | | | 18,658 | | | | | 862,162 | | | | 907,034 | | | | $ | 2,913,863 | | | $ | 2,892,582 | | LIABILITIES AND CAPITALIZATION | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | Currently payable long-term debt | | $ | 145,000 | | | $ | 145,000 | | Short-term borrowings- | | | | | | | | | Associated companies | | | 112,034 | | | | 31,402 | | Other | | | 250,000 | | | | 250,000 | | Accounts payable- | | | | | | | | | Associated companies | | | 49,981 | | | | 63,692 | | Other | | | 42,004 | | | | 48,633 | | Accrued taxes | | | 4,053 | | | | 13,264 | | Accrued interest | | | 13,730 | | | | 13,131 | | Other | | | 26,591 | | | | 31,730 | | | | | 643,393 | | | | 596,852 | | 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 | | | 912,380 | | | | 912,441 | | Accumulated other comprehensive loss | | | (126,103 | ) | | | (127,997 | ) | Retained earnings | | | 94,803 | | | | 76,113 | | Total common stockholder's equity | | | 969,632 | | | | 949,109 | | Long-term debt and other long-term obligations | | | 633,355 | | | | 633,132 | | | | | 1,602,987 | | | | 1,582,241 | | NONCURRENT LIABILITIES: | | | | | | | | | Regulatory liabilities | | | 48,847 | | | | 136,579 | | Accumulated deferred income taxes | | | 183,906 | | | | 169,807 | | Retirement benefits | | | 172,544 | | | | 172,718 | | Asset retirement obligations | | | 87,395 | | | | 87,089 | | Power purchase contract liability | | | 112,462 | | | | 83,600 | | Other | | | 62,329 | | | | 63,696 | | | | | 667,483 | | | | 713,489 | | COMMITMENTS AND CONTINGENCIES (Note 8) | | | | | | | | | | | $ | 2,913,863 | | | $ | 2,892,582 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company | | are an integral part of these balance sheets. | | | | | | | | |
Competitive Energy Services – Third Quarter 2009 Compared with Third Quarter 2008
Net income for this segment was $183 million in the third quarter of 2009 compared to $164 million in the same period of 2008. The $19 million increase in net income principally reflects an increase in investment income offset by a decrease in gross sales margins.
Revenues –
Total revenues decreased $139 million in the third quarter of 2009 primarily due to lower generation sales to the Ohio Companies, partially offset by higher non-affiliated retail generation sales volumes.
The decrease in total revenues resulted from the following sources:
| | Three Months | | | | | | Ended September 30 | | Increase | | Revenues By Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Non-Affiliated Generation Sales: | | | | | | | | | | | 232 | | | 171 | | | 61 | | | | | 212 | | | 210 | | | 2 | | Total Non-Affiliated Generation Sales | | | 444 | | | 381 | | | 63 | | Affiliated Generation Sales | | | 616 | | | 786 | | | (170 | | | | | 17 | | | 47 | | | (30 | | | | | 30 | | | 32 | | | (2 | ) | | | | 1,107 | | | 1,246 | | | (139 | |
The higher retail revenues reflect the acquisition of government aggregation programs in Ohio and the acquisition of new retail customer contracts in the MISO and PJM markets in the third quarter of 2009. FES has signed new government aggregation contracts with 50 communities that provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from lower sales volumes and higher prices in the PJM market offset by lower prices in the MISO market.
The lower affiliated company generation revenues were due primarily to a decrease in sales volumes to the Ohio Companies partially offset by higher unit prices for sales to the Ohio Companies and higher sales volumes to the Pennsylvania Companies. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
Source of Change in Non-Affiliated Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 10.7% increase in sales volumes | | $ | 19 | | Change in prices | | | 42 | | | | | 61 | | Wholesale: | | | | | Effect of 2.8% decrease in sales volumes | | | (6 | ) | Change in prices | | | 8 | | | | | 2 | | Net Increase in Non-Affiliated Generation Revenues | | $ | 63 | |
Source of Change in Affiliated Generation Revenues | | | | | | (In millions) | | Ohio Companies: | | | | | Effect of 47.8% decrease in sales volumes | | $ | (297 | ) | Change in prices | | | 115 | | | | | (182 | ) | Pennsylvania Companies: | | | | | Effect of 12.2% increase in sales volumes | | | 19 | | Change in prices | | | (7 | ) | | | | 12 | | Net Decrease in Affiliated Generation Revenues | | $ | (170 | ) |
PENNSYLVANIA ELECTRIC COMPANY | | | | | | | | | CONSOLIDATED STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | Three Months Ended | | | | March 31 | | | | 2009 | | | 2008 | | | | (In thousands) | | | | | | | | | CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | | Net income | | $ | 18,690 | | | $ | 21,392 | | Adjustments to reconcile net income to net cash from operating activities- | | | | | | Provision for depreciation | | | 14,455 | | | | 12,516 | | Amortization of regulatory assets | | | 16,141 | | | | 16,346 | | Deferral of new regulatory assets | | | (7,365 | ) | | | (3,526 | ) | Deferred costs recoverable as regulatory assets | | | (20,022 | ) | | | (8,403 | ) | Deferred income taxes and investment tax credits, net | | | 11,833 | | | | 10,541 | | Accrued compensation and retirement benefits | | | 431 | | | | (10,488 | ) | Cash collateral | | | - | | | | 301 | | Increase in operating assets- | | | | | | | | | Receivables | | | (1,709 | ) | | | (13,701 | ) | Prepayments and other current assets | | | (49,707 | ) | | | (40,591 | ) | Increase (Decrease) in operating liabilities- | | | | | | | | | Accounts payable | | | (5,340 | ) | | | (3,144 | ) | Accrued taxes | | | (9,065 | ) | | | (5,809 | ) | Accrued interest | | | 599 | | | | 510 | | Other | | | (988 | ) | | | 4,991 | | Net cash used for operating activities | | | (32,047 | ) | | | (19,065 | ) | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | New Financing- | | | | | | | | | Short-term borrowings, net | | | 80,632 | | | | 118,209 | | Redemptions and Repayments | | | | | | | | | Long-term debt | | | - | | | | (45,112 | ) | Dividend Payments- | | | | | | | | | Common stock | | | (15,000 | ) | | | (20,000 | ) | Net cash provided from financing activities | | | 65,632 | | | | 53,097 | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | Property additions | | | (28,190 | ) | | | (28,902 | ) | Sales of investment securities held in trusts | | | 18,800 | | | | 24,407 | | Purchases of investment securities held in trusts | | | (22,108 | ) | | | (29,083 | ) | Loan repayments to associated companies, net | | | (365 | ) | | | (610 | ) | Other | | | (1,732 | ) | | | 153 | | Net cash used for investing activities | | | (33,595 | ) | | | (34,035 | ) | | | | | | | | | | Net change in cash and cash equivalents | | | (10 | ) | | | (3 | ) | Cash and cash equivalents at beginning of period | | | 23 | | | | 46 | | Cash and cash equivalents at end of period | | $ | 13 | | | $ | 43 | | | | | | | | | | | The accompanying Notes to Consolidated Financial Statements as they relate to Pennsylvania Electric Company are | | an integral part of these statements. | | | | | | | | |
Transmission revenues decreased $30 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.
Expenses -
Total expenses decreased $21 million in the third quarter of 2009 due to the following factors:
· | Fuel costs decreased $54 million due to decreased generation volumes ($109 million), partially offset by higher unit prices ($55 million). |
· | Purchased power costs decreased $16 million due primarily to lower volume requirements ($71 million), partially offset by higher unit costs ($55 million) resulting from higher capacity costs. |
· | Fossil operating costs decreased $14 million due to a reduction in contractor and material costs, resulting from FirstEnergy’s cost control initiatives. |
· | Nuclear operating costs decreased $12 million due primarily to lower labor and employee benefit expenses of $6 million and reductions in contractor costs of $5 million. |
· | Other operating expenses increased $32 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and increased pension costs. |
· | Transmission expense increased $41 million due primarily to increased transmission costs in MISO of $24 million and higher congestion expenses in PJM of $15 million. |
· | Higher depreciation expense of $2 million was due primarily to NGC's increased ownership interests in Perry and Beaver Valley Unit 2 following its purchase of lease equity interests. |
Other Expense –
Total other expense in the third quarter of 2009 was $149 million lower than the third quarter of 2008, primarily due to a $146 million increase in earnings from nuclear decommissioning trust investments and a $3 million decrease in interest expense (net of capitalized interest).
Ohio Transitional Generation Services – Third Quarter 2009 Compared with Third Quarter 2008
Net income for this segment decreased $10 million to $9 million in the third quarter of 2009 from $19 million in the same period of 2008. Higher purchased power costs were partially offset by higher generation revenues and lower operating expenses.
Revenues –
The decrease in reported segment revenues resulted from the following sources:
| | Three Months | | | | | | | Ended September 30 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | | | | | | | | | | | | | | $ | 726 | | $ | 675 | | $ | 51 | | | | | - | | | 4 | | | (4 | ) | | | | 726 | | | 679 | | | 47 | | | | | 11 | | | 134 | | | (123 | ) | | | | 2 | | | - | | | 2 | | | | $ | 739 | | $ | 813 | | $ | (74 | ) |
COMBINED MANAGEMENT’S DISCUSSIONThe following table summarizes the price and volume factors contributing to the increase in sales revenues from retail customers:
Source of Change in Retail Generation Revenues | | | | | | (In millions) | | Effect of 17% decrease in sales volumes | | $ | (116 | ) | Change in prices | | | 167 | | Total Increase in Retail Generation Revenues | | $ | 51 | |
The decrease in generation sales volumes was primarily due to increased customer shopping resulting from certain government aggregation programs in Ohio, lower weather-related usage and economic conditions in the Ohio Companies’ service territory. Average prices increased primarily due to the result of the Ohio Companies' CBP. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs was included in the generation rate established under the CBP.
Decreased transmission revenue of $123 million resulted from the termination of the transmission tariff (as discussed above), reduced MISO revenues and lower sales volumes. Prior to June 1, 2009, the difference between transmission revenues and transmission costs incurred was deferred, resulting in no material impact to current period earnings.
Expenses -
Purchased power costs were $91 million higher due primarily to higher unit costs, partially offset by a decrease in volumes. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase (Decrease) | | | | (In millions) | | | | | | | Change due to increased unit costs | | $ | 194 | | Change due to decreased volumes | | | (103 | ) | | | $ | 91 | |
The decrease in purchased volumes was due to the lower retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' CBP for retail customers during the third quarter of 2009 (see Regulatory Matters – Ohio).
Other operating expenses decreased $119 million due to lower MISO transmission-related expenses (effective June 1, 2009 transmission costs are paid by the generation suppliers) and increased intersegment credits related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets decreased by $29 million in the third quarter of 2009 due primarily to lower MISO transmission cost amortization.
Summary of Results of Operations – First Nine Months of 2009 Compared with the First Nine Months of 2008
Financial results for FirstEnergy's major business segments in the first nine months of 2009 and 2008 were as follows:
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | First Nine Months 2009 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 5,823 | | | $ | 929 | | | $ | 2,499 | | | $ | - | | | $ | 9,251 | | Other | | | 413 | | | | 400 | | | | 20 | | | | (71 | ) | | | 762 | | Internal | | | - | | | | 2,349 | | | | - | | | | (2,349 | ) | | | - | | Total Revenues | | | 6,236 | | | | 3,678 | | | | 2,519 | | | | (2,420 | ) | | | 10,013 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | - | | | | 890 | | | | - | | | | - | | | | 890 | | Purchased power | | | 2,853 | | | | 551 | | | | 2,425 | | | | (2,349 | ) | | | 3,480 | | Other operating expenses | | | 1,167 | | | | 1,001 | | | | 22 | | | | (87 | ) | | | 2,103 | | Provision for depreciation | | | 331 | | | | 201 | | | | - | | | | 18 | | | | 550 | | Amortization of regulatory assets | | | 791 | | | | - | | | | 112 | | | | - | | | | 903 | | Deferral of new regulatory assets | | | - | | | | - | | | | (136 | ) | | | - | | | | (136 | ) | General taxes | | | 480 | | | | 84 | | | | 6 | | | | 17 | | | | 587 | | Total Expenses | | | 5,622 | | | | 2,727 | | | | 2,429 | | | | (2,401 | ) | | | 8,377 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 614 | | | | 951 | | | | 90 | | | | (19 | ) | | | 1,636 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 110 | | | | 136 | | | | 1 | | | | (40 | ) | | | 207 | | Interest expense | | | (343 | ) | | | (106 | ) | | | - | | | | (306 | ) | | | (755 | ) | Capitalized interest | | | 3 | | | | 42 | | | | - | | | | 51 | | | | 96 | | Total Other Expense | | | (230 | ) | | | 72 | | | | 1 | | | | (295 | ) | | | (452 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 384 | | | | 1,023 | | | | 91 | | | | (314 | ) | | | 1,184 | | Income taxes | | | 154 | | | | 409 | | | | 36 | | | | (169 | ) | | | 430 | | Net Income | | | 230 | | | | 614 | | | | 55 | | | | (145 | ) | | | 754 | | Less: Noncontrolling interest income (loss) | | | - | | | | - | | | | - | | | | (14 | ) | | | (14 | ) | Earnings available to FirstEnergy Corp. | | $ | 230 | | | $ | 614 | | | $ | 55 | | | $ | (131 | ) | | $ | 768 | |
| | | | | | | | Ohio | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | Other and | | | | | | | Delivery | | | Energy | | | Generation | | | Reconciling | | | FirstEnergy | | First Nine Months 2008 Financial Results | | Services | | | Services | | | Services | | | Adjustments | | | Consolidated | | | | (In millions) | | Revenues: | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | Electric | | $ | 6,567 | | | $ | 994 | | | $ | 2,142 | | | $ | - | | | $ | 9,703 | | Other | | | 484 | | | | 170 | | | | 61 | | | | 8 | | | | 723 | | Internal | | | - | | | | 2,266 | | | | - | | | | (2,266 | ) | | | - | | Total Revenues | | | 7,051 | | | | 3,430 | | | | 2,203 | | | | (2,258 | ) | | | 10,426 | | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 1 | | | | 999 | | | | - | | | | - | | | | 1,000 | | Purchased power | | | 3,228 | | | | 648 | | | | 1,766 | | | | (2,266 | ) | | | 3,376 | | Other operating expenses | | | 1,288 | | | | 906 | | | | 268 | | | | (88 | ) | | | 2,374 | | Provision for depreciation | | | 309 | | | | 179 | | | | - | | | | 12 | | | | 500 | | Amortization of regulatory assets | | | 747 | | | | - | | | | 48 | | | | - | | | | 795 | | Deferral of new regulatory assets | | | (274 | ) | | | - | | | | 13 | | | | - | | | | (261 | ) | General taxes | | | 491 | | | | 82 | | | | 4 | | | | 19 | | | | 596 | | Total Expenses | | | 5,790 | | | | 2,814 | | | | 2,099 | | | | (2,323 | ) | | | 8,380 | | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | 1,261 | | | | 616 | | | | 104 | | | | 65 | | | | 2,046 | | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | 133 | | | | (1 | ) | | | 1 | | | | (60 | ) | | | 73 | | Interest expense | | | (305 | ) | | | (116 | ) | | | (1 | ) | | | (137 | ) | | | (559 | ) | Capitalized interest | | | 2 | | | | 30 | | | | - | | | | 4 | | | | 36 | | Total Other Expense | | | (170 | ) | | | (87 | ) | | | - | | | | (193 | ) | | | (450 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | 1,091 | | | | 529 | | | | 104 | | | | (128 | ) | | | 1,596 | | Income taxes | | | 436 | | | | 212 | | | | 42 | | | | (105 | ) | | | 585 | | Net Income | | | 655 | | | | 317 | | | | 62 | | | | (23 | ) | | | 1,011 | | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | 1 | | | | 1 | | Earnings available to FirstEnergy Corp. | | $ | 655 | | | $ | 317 | | | $ | 62 | | | $ | (24 | ) | | $ | 1,010 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Changes Between First Nine Months 2009 | | | | | | | | | | | | | | | | | | and First Nine Months 2008 | | | | | | | | | | | | | | | | | | | | | Financial Results Increase (Decrease) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Revenues: | | | | | | | | | | | | | | | | | | | | | External | | | | | | | | | | | | | | | | | | | | | Electric | | $ | (744 | ) | | $ | (65 | ) | | $ | 357 | | | $ | - | | | $ | (452 | ) | Other | | | (71 | ) | | | 230 | | | | (41 | ) | | | (79 | ) | | | 39 | | Internal | | | - | | | | 83 | | | | - | | | | (83 | ) | | | - | | Total Revenues | | | (815 | ) | | | 248 | | | | 316 | | | | (162 | ) | | | (413 | ) | | | | | | | | | | | | | | | | | | | | | | Expenses: | | | | | | | | | | | | | | | | | | | | | Fuel | | | (1 | ) | | | (109 | ) | | | - | | | | - | | | | (110 | ) | Purchased power | | | (375 | ) | | | (97 | ) | | | 659 | | | | (83 | ) | | | 104 | | Other operating expenses | | | (121 | ) | | | 95 | | | | (246 | ) | | | 1 | | | | (271 | ) | Provision for depreciation | | | 22 | | | | 22 | | | | - | | | | 6 | | | | 50 | | Amortization of regulatory assets | | | 44 | | | | - | | | | 64 | | | | - | | | | 108 | | Deferral of new regulatory assets | | | 274 | | | | - | | | | (149 | ) | | | - | | | | 125 | | General taxes | | | (11 | ) | | | 2 | | | | 2 | | | | (2 | ) | | | (9 | ) | Total Expenses | | | (168 | ) | | | (87 | ) | | | 330 | | | | (78 | ) | | | (3 | ) | | | | | | | | | | | | | | | | | | | | | | Operating Income | | | (647 | ) | | | 335 | | | | (14 | ) | | | (84 | ) | | | (410 | ) | Other Income (Expense): | | | | | | | | | | | | | | | | | | | | | Investment income | | | (23 | ) | | | 137 | | | | - | | | | 20 | | | | 134 | | Interest expense | | | (38 | ) | | | 10 | | | | 1 | | | | (169 | ) | | | (196 | ) | Capitalized interest | | | 1 | | | | 12 | | | | - | | | | 47 | | | | 60 | | Total Other Expense | | | (60 | ) | | | 159 | | | | 1 | | | | (102 | ) | | | (2 | ) | | | | | | | | | | | | | | | | | | | | | | Income Before Income Taxes | | | (707 | ) | | | 494 | | | | (13 | ) | | | (186 | ) | | | (412 | ) | Income taxes | | | (282 | ) | | | 197 | | | | (6 | ) | | | (64 | ) | | | (155 | ) | Net Income | | | (425 | ) | | | 297 | | | | (7 | ) | | | (122 | ) | | | (257 | ) | Less: Noncontrolling interest income | | | - | | | | - | | | | - | | | | (15 | ) | | | (15 | ) | Earnings available to FirstEnergy Corp. | | $ | (425 | ) | | $ | 297 | | | $ | (7 | ) | | $ | (107 | ) | | $ | (242 | ) |
Energy Delivery Services – First Nine Months of 2009 Compared to First Nine Months of 2008
Net income decreased $425 million to $230 million in the first nine months of 2009 compared to $655 million in the first nine months of 2008, primarily due to lower revenues and decreased deferrals of new regulatory assets, partially offset by lower purchased power and other operating expenses.
Revenues –
The decrease in total revenues resulted from the following sources:
| | Nine Months | | | | | | Ended September 30 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | | (193 | ) | | | | | | | | | | (213 | | | | | | | | | | | (406 | ) | | | | | | | | | | (17 | ) | | | | | | | | | | 4 | | | | | | | | | | | (815 | ) |
The decrease in distribution deliveries by customer class are summarized in the following table:
Electric Distribution KWH Deliveries | | | | | | | (3.7) | | | | | (4.7) | | | | | (18.0) | | Total Distribution KWH Deliveries | | | (8.6) | |
The lower revenues from distribution deliveries were due to reductions in sales volume and lower unit prices. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territories. In the industrial sector, KWH deliveries declined due to major automotive customers (25.0%) and steel customers (44.4%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).
The following table summarizes the price and volume factors contributing to the $406 million decrease in generation revenues in the first nine months of 2009 compared to the same period of 2008:
| | Increase | | Sources of Change in Generation Revenues | | (Decrease) | | | | (In millions) | | Retail: | | | | | Effect of 8% decrease in sales volumes | | $ | (208 | ) | Change in prices | | | | | | | | | ) | Wholesale: | | | | | Effect of 14% decrease in sales volumes | | | (108 | ) | Change in prices | | | | ) | | | | | ) | Net Decrease in Generation Revenues | | $ | (406 | ) |
The decrease in retail generation sales volumes was primarily due to weaker economic conditions and reduced weather-related usage. Cooling degree days decreased by 17% in the first nine months of 2009, while heating degree days increased by 3% compared to the same period last year. The increase in retail generation prices during the first nine months of 2009 was due to higher generation rates for JCP&L and Penn under their power procurement processes. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.
Transmission revenues decreased $17 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders.
Expenses –
Total expenses decreased by $168 million due to the following:
| · | Purchased power costs were $375 million lower in the first nine months of 2009 due to reduced volumes and an increase in the amount of NUG costs deferred, partially offset by higher unit costs. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from its BGS auction process. The following table summarizes the sources of changes in purchased power costs: |
Source of Change in Purchased Power | | Increase (Decrease) | | | | (In millions) | | Purchases from non-affiliates: | | | | | Change due to increased unit costs | | $ | 196 | | Change due to decreased volumes | | | (471 | ) | | | | (275 | ) | Purchases from FES: | | | | | Change due to decreased unit costs | | | (23 | ) | Change due to increased volumes | | | 57 | | | | | 34 | | | | | | | Increase in NUG costs deferred | | | (134 | ) | Net Decrease in Purchased Power Costs | | $ | (375 | ) |
· PJM transmission expenses were lower by $164 million, resulting primarily from reduced volumes and lower congestion costs.
· Organizational restructuring charges of $32 million and increased pension costs of $102 million were partially offset by lower labor expenses of $50 million. · An increase in other operating expense of $32 million resulted from recognition of economic development and energy efficiency obligations in accordance with the PUCO-approved ESP.
· Contractor and material expenses decreased $48 million, reflecting more costs dedicated to capital projects compared to the prior year.
· Storm related costs were $6 million lower in the first nine months of 2009.
· Lower general business expenses of $18 million reflected FirstEnergy’s cost control initiatives.
· A $44 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets and PJM transmission cost amortization in the first nine months of 2009, partially offset by the cessation of transition cost amortization for OE and TE. ·A $274 million decrease in the deferral of new regulatory assets was principally due to the absence in 2009 of PJM transmission cost deferrals and RCP distribution cost deferrals by the Ohio Companies. · Depreciation expense increased $22 million due to property additions since the third quarter of 2008.
· General taxes decreased $11 million due to lower gross receipts taxes.
Other Expense –
Other expense increased $60 million in the first nine months of 2009 compared to 2008. Lower investment income of $23 million resulted primarily from repaid notes receivable from affiliates since the third quarter of 2008. Higher interest expense (net of capitalized interest) of $38 million resulted from debt issuances described above under Financing Activities.
Competitive Energy Services – First Nine Months of 2009 Compared to First Nine Months of 2008
Net income increased to $614 million in the first nine months of 2009 compared to $317 million in the same period of 2008. The increase in net income includes FGCO's $252 million gain from the sale of a 9% participation interest in OVEC ($158 million after tax), an increase in investment income, and an increase in gross sales margins.
Revenues –
Total revenues increased $248 million in the first nine months of 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.
The increase in reported segment revenues resulted from the following sources:
| | Nine Months | | | | | | | Ended September 30 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Non-Affiliated Generation Sales: | | | | | | | | | | | | | $ | 406 | | $ | 485 | | $ | (79 | ) | | | | 523 | | | 509 | | | 14 | | Total Non-Affiliated Generation Sales | | | 929 | | | 994 | | | (65 | ) | Affiliated Generation Sales | | | 2,349 | | | 2,266 | | | 83 | | | | | 57 | | | 113 | | | (56 | ) | Sale of OVEC participation interest | | | 252 | | | - | | | 252 | | | | | 91 | | | 57 | | | 34 | | | | $ | 3,678 | | $ | 3,430 | | $ | 248 | |
The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue in both the PJM and MISO markets. The increase in MISO retail revenue is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, offset by decreased sales volumes in PJM.
The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES versus other suppliers, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.
In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders. Effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.
The following tables summarize the price and volume factors contributing to changes in revenues from generation sales:
| | Increase | | Source of Change in Non-Affiliated Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 34.3% decrease in sales volumes | | $ | (166 | ) | Change in prices | | | | | | | | | ) | Wholesale: | | | | | Effect of 3.5% decrease in sales volumes | | | (18 | ) | Change in prices | | | | | | | | | | Net Decrease in Non-Affiliated Generation Revenues | | | | ) |
| | Increase | | Source of Change in Affiliated Generation Revenues | | | | | | (In millions) | | Ohio Companies: | | | | | Effect of 28.9% decrease in sales volumes | | $ | (508) | | Change in prices | | | | | | | | | | Pennsylvania Companies: | | | | | Effect of 11.1% increase in sales volumes | | | 57 | | Change in prices | | | | | | | | | | Net Increase in Affiliated Generation Revenues | | | | |
Transmission revenues decreased $56 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008. Other revenue increased $34 million primarily due to rental income associated with NGC's acquisition of equity interests in the Perry and Beaver Valley Unit 2 leases.
Expenses -
Total expenses decreased $87 million in the first nine months of 2009 due to the following factors:
· Fuel costs decreased $109 million due to lower generation volumes ($227 million), partially offset by higher unit prices ($118 million). · Purchased power costs decreased $97 million due to lower volume ($170 million), partially offset by higher unit prices ($73 million) that resulted primarily from higher capacity costs.
· Fossil operating costs decreased $46 million due primarily to a reduction in contractor and material costs ($38 million) and more labor dedicated to capital projects ($6 million) compared to the prior year.
· Nuclear operating costs decreased $4 million in the first nine months of 2009 as lower labor and employee benefits expense was partially offset by the cost of an additional refueling outage during the 2009 period.
· Other expense increased $83 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension costs.
· Transmission expense increased $64 million due primarily to increased net congestion in PJM and higher loss expenses in MISO and PJM.
· Higher depreciation expense of $22 million was due to NGC's increased ownership interest in Beaver Valley Unit 2 and Perry.
Other Expense –
Total other expense in the first nine months of 2009 was $159 million lower than the first nine months of 2008, primarily due to a $137 million increase in earnings from nuclear decommissioning trust investments and a decline in interest expense (net of capitalized interest) of $22 million due to the repayment of notes payable to affiliates.
Ohio Transitional Generation Services – First Nine Months of 2009 Compared to First Nine Months of 2008
Net income for this segment decreased $7 million to $55 million in the first nine months of 2009 from $62 million in the same period of 2008. Higher purchased power expenses were partially offset by higher generation revenues and increased deferrals of regulatory assets.
Revenues –
The increase in reported segment revenues resulted from the following sources:
| | Nine Months Ended | | | | | | September 30 | | | | Revenues by Type of Service | | 2009 | | 2008 | | Increase (Decrease) | | | | (In millions) | | | | | | | | | | | | | | | | | | | 455 | | | | | | | | | | | (9 | ) | | | | | | | | | | 446 | | | | | | | | | | | (127 | | | | | | | | | | | (3 | ) | | | | | | | | | | 316 | |
The following table summarizes the price and volume factors contributing to the net increase in sales revenues from retail customers: Source of Change in Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 3% decrease in sales volumes | | $ | (52 | ) | Change in prices | | | | | Net Increase in Retail Generation Revenues | | | | |
The decrease in generation sales volume in the first nine months of 2009 was primarily due to milder weather and economic conditions in the Ohio Companies' service territory. Average price increases reflect an increase in the Ohio Companies' fuel cost recovery riders that were in effect from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended with the recovery of transmission costs now included in the generation rate established under the Ohio Companies' CBP.
Decreased transmission revenue of $127 million resulted primarily from the termination of the transmission tariff effective June 1, 2009, lower MISO transmission related revenues and decreased sales volumes.
Expenses -
Purchased power costs were $659 million higher due primarily to higher unit costs for power. The factors contributing to the higher costs are summarized in the following table:
Source of Change in Purchased Power | | Increase (Decrease) | | | | (In millions) | | | | | | | Change due to increased unit costs | | $ | 712 | | Change due to decreased volumes | | | (53 | ) | | | $ | 659 | |
The decrease in purchased volumes was due to the lower retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' power supply procurement processes for retail customers during the first nine months of 2009 (see Regulatory Matters – Ohio).
Other operating expenses decreased $246 million due primarily to lower MISO transmission expenses and higher intersegment cost reimbursements related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $64 million in the first nine months of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $149 million due to CEI’s deferral of purchased power costs as approved by the PUCO.
Other – First Nine Months of 2009 Compared to First Nine Months of 2008
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 $107 million decrease in FirstEnergy's net income in the first nine months of 2009 compared to the same period in 2008. The decrease resulted primarily from debt redemption costs ($90 million, net of taxes) and the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes).
CAPITAL RESOURCES AND ANALYSIS OF REGISTRANT SUBSIDIARIESLIQUIDITY
FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.
As of September 30, 2009, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.7 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of September 30, 2009, included the following (in millions):
Currently Payable Long-term Debt | | | | PCRBs supported by bank LOCs(1) | | $ | 1,553 | | FGCO and NGC unsecured PCRBs(1) | | 97 | | CEI secured notes(2) | | 150 | | Met-Ed unsecured notes(3) | | 100 | | Penelec unsecured notes(4) | | 35 | | NGC collateralized lease obligation bonds | | 44 | | Sinking fund requirements | | 41 | | | | $ | 2,020 | | | | | | (1) Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity. (2) Mature in November 2009. (3) Mature in March 2010. (4) Mature in August 2010. . | |
Short-Term Borrowings
FirstEnergy had approximately $1.7 billion of short-term borrowings as of September 30, 2009 and $2.4 billion as of December 31, 2008. FirstEnergy, along with certain of its subsidiaries, has access to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. As of October 30, 2009, FirstEnergy had $120 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. In August 2009, FGCO and FES cancelled an unused $300 million secured term loan facility with Credit Suisse. FirstEnergy's available liquidity as of October 30, 2009, is summarized in the following table:
Company | | Type | | Maturity | | Commitment | | Available Liquidity as of October 30, 2009 | | | | | | | | (In millions) | | FirstEnergy(1) | | Revolving | | Aug. 2012 | | $ | 2,750 | | $ | 1,334 | | FirstEnergy and FES | | Bank lines | | Various(2) | | | 120 | | | 20 | | Ohio and Pennsylvania Companies | | Receivables financing | | Various(3) | | | 550 | | | 306 | | | | | | Subtotal | | $ | 3,420 | | $ | 1,660 | | | | | | Cash | | | - | | | 748 | | | | | | Total | | $ | 3,420 | | $ | 2,408 | | | | | | | | | | | | | | (1) FirstEnergy Corp. and subsidiary borrowers. (2) $100 million expires March 31, 2011; $20 million uncommitted line of credit has no expiration date. (3) $180 million expires December 18, 2009; $370 million expires February 22, 2010. | |
Revolving Credit Facility
FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.
The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2009:
| | Revolving | | Regulatory and | | | Credit Facility | | Other Short-Term | | | | | | | | (In millions) | | FirstEnergy | | $ | 2,750 | | $ | - | (1) | FES | | | 1,000 | | | - | (1) | OE | | | 500 | | | 500 | | Penn | | | 50 | | | 39 | (2) | CEI | | | 250 | (3) | | 500 | | TE | | | 250 | (3) | | 500 | | JCP&L | | | 425 | | | 428 | (2) | Met-Ed | | | 250 | | | 300 | (2) | Penelec | | | 250 | | | 300 | (2) | ATSI | | | - | (4) | | 50 | | | | | | | | | | (1)No regulatory approvals, statutory or charter limitations applicable. (2)Excluding amounts which may be borrowed under the regulated companies' money pool. (3)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody's. (4)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody's or (ii) FirstEnergy has guaranteed ATSI's obligations of such borrower under the facility. |
Under the revolving credit facility, borrowers may request the issuance of LOCs expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under the facility and against the applicable borrower's borrowing sub-limit.
The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2009, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:
Borrower | | | FirstEnergy(1) | | 61.6 | % | FES | | 54.2 | % | OE | | 46.6 | % | Penn | | 32.9 | % | CEI | | 59.3 | % | TE | | 53.9 | % | JCP&L | | 34.9 | % | Met-Ed | | 41.6 | % | Penelec | | 54.1 | % |
(1) | As of September 30, 2009, FirstEnergy could issue additional debt of approximately $2.4 billion, or recognize a reduction in equity of approximately $1.3 billion, and remain within the limitations of the financial covenants required by its revolving credit facility. |
The revolving credit facility does not contain provisions that either restrict the ability to borrow or accelerate repayment of outstanding advances as a result of any change in credit ratings. Pricing is defined in "pricing grids," whereby the cost of funds borrowed under the facility is related to the credit ratings of the company borrowing the funds.
FirstEnergy Money Pools
FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a combined presentationloan 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 nine months of 2009 was 0.78% for the regulated companies' money pool and 0.96% for the unregulated companies' money pool.
Pollution Control Revenue Bonds
As of September 30, 2009, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.
The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks:
| | Aggregate LOC | | | | Reimbursements of | LOC Bank | | Amount(3) | | LOC Termination Date | | LOC Draws Due | | | (In millions) | | | | | CitiBank N.A. | | $ | 166 | | June 2014 | | June 2014 | The Bank of Nova Scotia | | 255 | | Beginning June 2010 | | Shorter of 6 months or LOC termination date | The Royal Bank of Scotland | | 131 | | June 2012 | | 6 months | KeyBank(1) | | 266 | | June 2010 | | 6 months | Wachovia Bank | | 153 | | March 2014 | | March 2014 | Barclays Bank(2) | | 528 | | Beginning December 2010 | | 30 days | PNC Bank | | 70 | | Beginning November 2010 | | 180 days | Total | | $ | 1,569 | | | | | (1) Supported by four participating banks, with the LOC bank having 62% of the total commitment. (2) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3) Includes approximately $16 million of applicable interest coverage. |
In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were also remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain disclosures referencedLOC banks listed above in Management’s Narrative Analysisconnection with amendments to existing LOC and reimbursement agreements supporting twelve other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs. On August 14, 2009, $177 million of non-LOC supported fixed rate PCRBs were issued and sold on behalf of FGCO to pay a portion of the cost of acquiring, constructing and installing air quality facilities at its W.H. Sammis Generating Station. On October 1, 2009, FGCO and NGC repurchased approximately $52.1 million and $29.6 million of variable rate PCRBs, respectively. These PCRBs are secured by a corresponding series of FMBs until December 31, 2009. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in fixed-rate mode in the near future.
Long-Term Debt Capacity
As of September 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.5 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 $164 million and $32 million, respectively, as of September 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. As a result, the provisions for TE to incur additional secured debt do not apply. In August 2009 CEI issued $300 million of FMB. CEI restricted $150 million of the proceeds to fund the redemption of $150 million of secured notes due in November 2009.
Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of September 30, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing LOC and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million principal amount of FMBs related to three existing series of PCRBs (repurchased in October 2009, as described above).
In June 2009, a new FMB indenture became effective for NGC. Based upon NGC’s FMB indenture, net earnings and available bondable property additions, NGC had the capability to issue $264 million of additional FMBs as of September 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing LOC and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with NGC's delivery of a Surplus Margin Guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs ($29.6 million repurchased in October 2009, as described above) and approximately $181.3 million related to amendments to existing LOC and reimbursement agreements supporting three other series of PCRBs.
Met-Ed and Penelec had the capability to issue secured debt of approximately $376 million and $319 million, respectively, under provisions of their senior note indentures as of September 30, 2009.
FirstEnergy's access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of September 30, 2009. On August 3, 2009 Moody’s upgraded the majority of senior secured debt ratings of investment grade regulated utilities by one notch. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."
Issuer | | | Securities | | | S&P | | | Moody's | | | | | | | | FirstEnergy | | Senior unsecured | | BBB- | | Baa3 | | | | | | | | FES | | Senior secured | | BBB | | Baa1 | | | Senior unsecured | | BBB | | Baa2 | | | | | | | | OE | | Senior secured | | BBB+ | | A3 | | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Penn | | Senior secured | | A- | | A3 | | | | | | | | CEI | | Senior secured | | BBB+ | | Baa1 | | | Senior unsecured | | BBB | | Baa3 | | | | | | | | TE | | Senior secured | | BBB+ | | Baa1 | | | Senior unsecured | | BBB | | Baa3 | | | | | | | | JCP&L | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Met-Ed | | Senior unsecured | | BBB | | Baa2 | | | | | | | | Penelec | | Senior unsecured | | BBB | | Baa2 |
On September 22, 2008, FirstEnergy, along with the Shelf Registrants, filed an automatically effective shelf registration statement with the SEC for an unspecified number and amount of securities to be offered thereon. The shelf registration provides FirstEnergy the flexibility to issue and sell various types of securities, including common stock, preferred stock, debt securities, warrants, share purchase contracts, and share purchase units. The Shelf Registrants have utilized, and may in the future utilize, the shelf registration statement to offer and sell unsecured and, in some cases, secured debt securities.
Changes in Cash Position
As of September 30, 2009, FirstEnergy had $838 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of September 30, 2009, approximately $794 million of cash and cash equivalents represented temporary overnight deposits. As of September 30, 2009 and December 31, 2008, FirstEnergy had $171 million and $17 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.
During the first nine months of 2009, FirstEnergy received $621 million of cash from dividends and equity repurchases from its subsidiaries and paid $503 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the only utility subsidiaries currently precluded from that action.
Cash Flows From Operating Activities
FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $33 million during the first nine months of 2009 compared to the comparable period in 2008, as summarized in the following table:
| | Nine Months Ended September 30 | | | | | Operating Cash Flows | | 2009 | | 2008 | | Increase (Decrease) | | | | (In millions) | | Net income | | $ | 754 | | $ | 1,011 | | $ | (257 | ) | Non-cash charges and other adjustments | | | 1,755 | | | 1,033 | | | 722 | | Pension trust contribution | | | (500) | | | - | | | (500 | ) | Working capital and other | | | (545) | | | (613 | ) | | 68 | | | | $ | 1,464 | | $ | 1,431 | | $ | 33 | |
The increase in non-cash charges and other adjustments is primarily due to higher net amortization of regulatory assets ($233 million), including CEI’s $216 million regulatory asset impairment, changes in accrued compensation and retirement benefits ($147 million), changes in deferred income taxes and investment tax credits, net ($143 million), and an increase in the provision for depreciation ($50 million). Also included in non-cash charges and other adjustments was a $142 million charge relating to debt redemptions in 2009, of which $122 million was related primarily to the premium paid and included as a cash outflow in financing activities. The changes in working capital and other primarily resulted from a $73 million decrease in stock-based compensation payments and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.
Cash Flows From Financing Activities
In the first nine months of 2009, cash provided from financing activities was $617 million compared to $911 million in the first nine months of 2008. The decrease was primarily due to increased long-term debt redemptions and reduced short-term borrowings, partially offset by increased long-term debt issuances in the first nine months of 2009. The increased long-term debt redemptions were primarily due to the $1.2 billion tender offer completed by FirstEnergy in September 2009, including approximately $122 million of premiums and redemption expenses paid. The following table summarizes security issuances (net of any discounts) and redemptions, including premiums paid to debt holders as a result of the tender offer.
| | Nine Months Ended | | | | September 30 | | Securities Issued or Redeemed | | 2009 | | 2008 | | | | (In millions) | | New issues | | | | | | | | First mortgage bonds | | $ | 398 | | $ | - | | Pollution control notes | | | 859 | | | 611 | | Senior secured notes | | | 297 | | | - | | Unsecured notes | | | 2,597 | | | 20 | | | | $ | 4,151 | | $ | 631 | | | | | | | | | | Redemptions | | | | | | | | First mortgage bonds | | $ | - | | $ | 1 | | Pollution control notes | | | 687 | | | 534 | | Senior secured notes | | | 54 | | | 23 | | Unsecured notes* | | | 1,472 | | | 175 | | | | $ | 2,213 | | $ | 733 | | | | | | | | | | Short-term borrowings, net | | $ | (764) | | $ | 1,489 | | | | | | | | | | * Including premiums and redemption expenses paid of $122 million. | |
The following table summarizes new debt issuances (excluding PCRB issuances and refinancings) during 2009.
| | | | | | | | | | | | | | | | | | | | | | Met-Ed* | | 01/20/2009 | | $300 | | 7.70% Senior Notes | | 2019 | | Repay short-term borrowings | | | | | | | | | | | | JCP&L* | | 01/27/2009 | | $300 | | 7.35% Senior Notes | | 2019 | | Repay short-term borrowings, fund capital expenditures and other general purposes | | | | | | | | | | | | TE* | | 04/24/2009 | | $300 | | 7.25% Senior Secured Notes | | 2020 | | Repay short-term borrowings, fund capital expenditures and other general purposes | | | | | | | | | | | | Penn | | 06/30/2009 | | $100 | | 6.09% FMB | | 2022 | | Fund capital expenditures and repurchase equity from OE | | | | | | | | | | | | FES | | 08/07/2009 | | $400 $600 $500 | | 4.80% Senior Notes 6.05% Senior Notes 6.80% Senior Notes | | 2015 2021 2039 | | Repay short-term borrowings and other general purposes | | | | | | | | | | | | CEI* | | 08/18/2009 | | $300 | | 5.50% FMB | | 2024 | | $150M placed with trustee for future debt redemption, repay short-term borrowings and other general purposes | | | | | | | | | | | | Penelec* | | 9/30/2009 | | $250 $250 | | 5.20% Senior Notes 6.15% Senior Notes | | 2020 2038 | | Repay short-term borrowings | | | | | | | | | | | | * Issued under the shelf registration statement referenced above. |
On October 30, 2009, Penelec provided notice for early redemption of its $35 million aggregate principal 7.77% Notes due August 2, 2010. The Notes are scheduled to be redeemed on November 30, 2009 with a make-whole redemption price.
Cash Flows From Investing Activities
Net cash flows used in investing activities resulted primarily from property additions. Additions for the energy delivery services segment primarily represent expenditures related to transmission and distribution facilities. Capital spending by the competitive energy services segment is principally generation-related. The following table summarizes investing activities for the nine months ended September 30, 2009 and 2008 by business segment:
Summary of Cash Flows | | Property | | | | | | | | Provided from (Used for) Investing Activities | | Additions | | Investments | | Other | | Total | | Sources (Uses) | | (In millions) | | Nine Months Ended September 30, 2009 | | | | | | | | | | | | | (524 | | | (121 | ) | | (35 | ) | | (680 | | Competitive energy services | | | (893 | | | (6 | | | (21 | ) | | (920 | | | | | (133 | | | - | | | (11 | | | (144 | | Inter-Segment reconciling items | | | (25 | | | (25 | ) | | 6 | | | (44 | | | | | (1,575 | | | (152 | ) | | (61 | | | (1,788 | | | | | | | | | | | | | | | | Nine Months Ended September 30, 2008 | | | | | | | | | | | | | | | | $ | (621 | ) | $ | 33 | | $ | (3 | ) | $ | (591 | ) | Competitive energy services | | | (1,430 | ) | | (13 | ) | | (121 | ) | | (1,564 | ) | | | | (106 | ) | | 57 | | | (54 | ) | | (103 | ) | Inter-Segment reconciling items | | | (20 | ) | | (12 | ) | | - | | | (32 | ) | | | $ | (2,177 | ) | $ | 65 | | $ | (178 | ) | $ | (2,290 | ) |
Net cash used for investing activities in the first nine months of 2009 decreased by $502 million compared to the first nine months of 2008. The decrease was principally due to a $602 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and the purchase of the partially-completed Fremont Energy Center. The decrease in property additions was partially offset by the absence in 2009 of cash proceeds from the sale of telecommunication assets in the first quarter of 2008 combined with increased restricted funds to be used for future debt redemptions.
During the last three months of 2009, capital requirements for property additions and capital leases are expected to be approximately $410 million, including approximately $65 million for nuclear fuel. FirstEnergy has additional requirements of approximately $164 million for maturing long-term debt during the remainder of 2009. These cash requirements are expected to be satisfied from a combination of internal cash, short-term credit arrangements and funds raised in the capital markets.
FirstEnergy's capital spending for the period 2009-2013 is expected to be approximately $8.0 billion (excluding nuclear fuel), of which approximately $1.7 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $295 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $130 million, respectively, as the nuclear fuel is consumed.
GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. Some of the guaranteed contracts contain collateral provisions that are contingent upon FirstEnergy’s credit ratings.
As of September 30, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:
| | Maximum | | Guarantees and Other Assurances | | | | | | (In millions) | | FirstEnergy Guarantees on Behalf of its Subsidiaries | | | | Energy and Energy-Related Contracts (1) | | $ | 385 | | LOC (long-term debt) – interest coverage (2) | | | 6 | | FirstEnergy guarantee of OVEC obligations | | | 300 | | Other (3) | | | 296 | | | | | 987 | | | | | | | Subsidiaries’ Guarantees | | | | | Energy and Energy-Related Contracts | | | 54 | | LOC (long-term debt) – interest coverage (2) | | | 6 | | FES’ guarantee of NGC’s nuclear property insurance | | | 77 | | FES’ guarantee of FGCO’s sale and leaseback obligations | | | 2,502 | | | | | 2,639 | | | | | | | Surety Bonds | | | 103 | | LOC (long-term debt) – interest coverage (2) | | | 4 | | LOC (non-debt) (4)(5) | | | 398 | | | | | 505 | | Total Guarantees and Other Assurances | | $ | 4,131 | |
| (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 $1.6 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets. |
| (3) | Includes guarantees of $80 million for nuclear decommissioning funding (see Nuclear Plant Matters below) assurances and $161 million supporting OE’s sale and leaseback arrangement. |
| (4) | Includes $58 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility. |
| (5) | Includes approximately $206 million pledged in connection with the sale and l easeback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry by OE. |
FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy 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 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 September 30, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $616 million as shown below:
Collateral Provisions | | FES | | Utilities | | Total | | | | (In millions) | | Credit rating downgrade to below investment grade | | $ | 305 | | $ | 115 | | $ | 420 | | Acceleration of payment or funding obligation | | | 80 | | | 63 | | | 143 | | Material adverse event | | | 53 | | | - | | | 53 | | Total | | $ | 438 | | $ | 178 | | $ | 616 | |
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 $699 million, consisting of $60 million due to “material adverse event” contractual clauses and $639 million due to a below investment grade credit rating.
Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ power portfolio as of September 30, 2009, and forward prices as of that date, FES had $183 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices), FES would be required to post an additional $45 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.
In connection with FES’ obligations to post and maintain collateral under the two-year PSA entered into by FES and the Utilities. This information should be readOhio Companies following the CBP auction on May 13-14, 2009, NGC entered into a Surplus Margin Guaranty in conjunction with (i) the amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.
FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, pursuant to guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the Utilities’ respective Consolidated Financial Statementsdebt obligations of each of FGCO and Management’s Narrative AnalysisNGC. Accordingly, present and future holders of Resultsindebtedness of Operations; (ii) the Combined Notes to Consolidated Financial Statements as they relate to FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.
OFF-BALANCE SHEET ARRANGEMENTS
FES and the Utilities;Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and (iii) FES’leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7 billion as of September 30, 2009.
FirstEnergy has equity ownership interests in certain businesses that are accounted for using the equity method of accounting. There are no undisclosed material contingencies related to these investments. Certain guarantees that FirstEnergy does not expect to have a material current or future effect on its financial condition, liquidity or results of operations are disclosed under "Guarantees and Other Assurances" above.
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 and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. Certain derivatives must be recorded at their fair value and marked to market. The majority of FirstEnergy's derivative hedging contracts qualify for the normal purchase and normal sale exception and are therefore excluded from the tables below. Contracts that are not exempt from such treatment include certain power purchase agreements with NUG entities that were structured pursuant to the Public Utility Regulatory Policies Act of 1978. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2009 are summarized in the following table:
| Three Months Ended | | Nine Months Ended | | | September 30, 2009 | | September 30, 2009 | | Fair Value of Commodity Derivative Contracts | | Non-Hedge | | Hedge | | Total | | Non-Hedge | | Hedge | | Total | | | (In millions) | | Change in the Fair Value of | | | | | | | | | | | | | Commodity Derivative Contracts: | | | | | | | | | | | | | Outstanding net liability at beginning of period | $ | (515 | ) | $ | (14 | ) | $ | (529 | ) | $ | (304 | ) | $ | (41 | ) | $ | (345 | ) | Additions/change in value of existing contracts | | (23 | ) | | 13 | | | (10 | ) | | (404 | ) | | 10 | | | (394 | ) | Settled contracts | | 92 | | | (5 | ) | | 87 | | | 262 | | | 25 | | | 287 | | Outstanding net liability at end of period (1) | $ | (446 | ) | $ | (6 | ) | $ | (452 | ) | $ | (446 | ) | $ | (6 | ) | $ | (452 | ) | | | | | | | | | | | | | | | | | | | | Non-commodity Net Liabilities at End of Period: | | | | | | | | | | | | | | | | | | | Interest rate swaps (2) | | - | | | (2 | ) | | (2 | ) | | - | | | (2 | ) | | (2 | ) | Net Liabilities - Derivative Contracts at End of Period | $ | (446 | ) | $ | (8 | ) | $ | (454 | ) | $ | (446 | ) | $ | (8 | ) | $ | (454 | ) | | | | | | | | | | | | | | | | | | | | Impact of Changes in Commodity Derivative Contracts(3) | | | | | | | | | | | | | | | | | | | Income statement effects (pre-tax) | $ | (2 | ) | $ | - | | $ | (2 | ) | $ | 2 | | $ | - | | $ | 2 | | Balance sheet effects: | | | | | | | | | | | | | | | | | | | Other comprehensive income (pre-tax) | $ | - | | $ | 8 | | $ | 8 | | $ | - | | $ | 35 | | $ | 35 | | Regulatory assets (net) | $ | (71 | ) | $ | - | | $ | (71 | ) | $ | 144 | | $ | - | | $ | 144 | |
| (1) | Includes $446 million in non-hedge commodity derivative contracts (primarily with NUGs) which are offset by a regulatory asset. |
| (2) | Interest rate swaps are treated as cash flow or fair value hedges. |
| (3) | Represents the change in value of existing contracts, settled contracts and changes in techniques/assumptions. |
Derivatives are included on the Consolidated Balance Sheet as of September 30, 2009 as follows:
Balance Sheet Classification | | Non-Hedge | | Hedge | | Total | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 239 | | | - | | | 239 | | Other non-current liabilities | | | (685) | | | (3) | | | (688) | | | | | (446) | | | (8) | | | (454) | |
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 5 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of September 30, 2009 are summarized by year in the following table:
Source of Information | | | | | | | | | | | | | | | | - Fair Value by Contract Year | | | | | | | | | | | | | | | | | | (In millions) | | Prices actively quoted(2) | | $ | (2) | | $ | (13 | ) | $ | - | | $ | - | | $ | - | | $ | - | | $ | (15 | ) | Other external sources(3) | | | (64) | | | (251 | ) | | (209 | ) | | (129 | ) | | - | | | - | | | (653 | ) | Prices based on models | | | | | | | | | | | | | | | | ) | | | | | | | Total | | | | | | | ) | | | ) | | | ) | | | ) | | | | | | ) |
(1) For the fourth quarter of 2009. (2) Represents exchange traded NYMEX futures and options. (3) Primarily represents contracts based on broker and ICE quotes.
FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2009. Based on derivative contracts held as of September 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4 million during the next 12 months.
Forward Starting Swap Agreements - Cash Flow Hedges
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 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 Utilities’ respectivedate of the debt issuance. For the three months and nine months ended September 30, 2009, FirstEnergy terminated forward swaps with a notional value of $2.3 billion and $2.4 billion, respectively. FirstEnergy recognized losses of approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will be amortized to interest expense over the life of the hedged debt.
| | September 30, 2009 | | December 31, 2008 | | | | Notional | | Maturity | | Fair | | Notional | | Maturity | | Fair | | | | Amount | | Date | | Value | | Amount | | Date | | Value | | | | (In millions) | | Cash flow hedges | | $ | | | | | | $ | (1 | | $ | | | | | | $ | | | | | | | | | | | | (1 | | | | | | | | | | | | | | | | | | | | - | | | | | | | | | | | | | $ | | | | | | $ | (2 | | $ | | | | | | $ | | |
Equity Price Risk
FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles, and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009, including a $27 million reduction that is applicable to the first nine months of 2009 (see Note 6). In the third quarter of 2009, the Plan also incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees (see Note 6). On September 2, 2009, FirstEnergy elected to remeasure its qualified defined pension plan due to a $500 million voluntary contribution made by the Utilities and ATSI. The remeasurement and voluntary contribution decreased FirstEnergy’s accumulated other comprehensive income by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million ($2 million is applicable to the third quarter of 2009) (see Note 6). Reductions in plan assets from investment losses during 2008 Annual Reportsresulted in a decrease to the plans' funded status of $1.7 billion and an after-tax decrease to common stockholders' equity of $1.2 billion. For the first eight months of 2009, the actual plan asset investment results were 9.4% compared to (23.8%) for 2008. As of December 31, 2008, the pension plan was underfunded and it remained underfunded after the voluntary contribution and remeasurement on Form 10-K.August 31, 2009. FirstEnergy currently estimates that additional cash contributions will be required in 2014 for the 2013 plan year.
Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of September 30, 2009, approximately 15% of the funds were invested in equity securities and 85% were invested in fixed income securities, with limitations related to concentration and investment grade ratings. The equity securities are carried at their market value of approximately $278 million as of September 30, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of September 30, 2009. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts based on the guidance for other-than-temporary impairments. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities were extended until 2036 and 2047 for Units 1 and 2, respectively. Renewal of the operating license for Beaver Valley Unit 1 (see Nuclear Plant Matters) is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC will continue to work with the NRC Staff as it completes its review of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.
CREDIT RISK
Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We engage in transactions for the purchase and sale of commodities including gas, electricity, coal and emission allowances. These transactions are often with major energy companies within the industry.
We maintain credit policies with respect to our counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of our credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2009, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 10.7% of our total approved credit risk.
OUTLOOK
State Regulatory Matters (Applicable to each of the Utilities)
In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Utilities' respective state regulatory plans. These provisions include:
· | restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities; | | | · | establishing or defining the PLR obligations to customers in the Utilities' service areas; | | | · | providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market; | | | · | itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges; | | | · | continuing regulation of the Utilities' transmission and distribution systems; and | | | · | requiring corporate separation of regulated and unregulated business activities. |
The Utilities and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $130$172 million as of March 31,September 30, 2009 (JCP&L - $54$42 million, Met-Ed - $102 million and Met-EdPenelec - $76$28 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed.Met-Ed and Penelec. The following table discloses net regulatory assets by company:
| | March 31, | | December 31, | | Increase | | | September 30, | | December 31, | | Increase | | Regulatory Assets* | | 2009 | | 2008 | | (Decrease) | | | Regulatory Assets | | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | | (In millions) | | OE | | $ | 545 | | $ | 575 | | $ | (30 | ) | | $ | 494 | | $ | 575 | | $ | (81 | ) | CEI | | | 618 | | | 784 | | | (166 | ) | | | 592 | | | 784 | | | (192 | ) | TE | | | 96 | | | 109 | | | (13 | ) | | | 77 | | | 109 | | | (32 | ) | JCP&L | | | 1,162 | | | 1,228 | | | (66 | ) | | | 950 | | | 1,228 | | | (278 | ) | Met-Ed | | | 490 | | | 413 | | | 77 | | | | 404 | | | 413 | | | (9 | ) | Penelec* | | | | 3 | | | - | | | 3 | | ATSI | | | | | | | | | | ) | | | | | | | | | | ) | Total | | | | | | | | | | ) | | | | | | | | | | ) |
* | Penelec had net regulatory liabilities of approximately $49 million and $137 million as of March 31, 2009 and December 31, 2008,
respectively.2008. These net regulatory liabilities are included in Other
Non-current Liabilities on the Consolidated Balance Sheets. |
Regulatory assets by source are as follows:
| | September 30, | | December 31, | | Increase | | Regulatory Assets By Source | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Regulatory transition costs | | $ | 1,142 | | $ | 1,452 | | $ | (310 | ) | Customer shopping incentives | | | 192 | | | 420 | | | (228 | ) | Customer receivables for future income taxes | | | 339 | | | 245 | | | 94 | | Loss on reacquired debt | | | 51 | | | 51 | | | - | | Employee postretirement benefits | | | 25 | | | 31 | | | (6 | ) | Nuclear decommissioning, decontamination | | | | | | | | | | | and spent fuel disposal costs | | | (152 | ) | | (57 | ) | | (95 | ) | Asset removal costs | | | (228 | ) | | (215 | ) | | (13 | ) | MISO/PJM transmission costs | | | 207 | | | 389 | | | (182 | ) | Purchased power costs | | | 356 | | | 214 | | | 142 | | Distribution costs | | | 525 | | | 475 | | | 50 | | Other | | | | | | | | | | ) | Total | | | | | | | | | | ) |
Reliability Initiatives In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation required JCP&L to respond to the NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. The NERC conducted on site interviews with personnel involved in responding to the event on June 16-17, 2009. On July 7, 2009, the NERC issued additional questions regarding the event and JCP&L replied as requested on August 6, 2009. JCP&L is not able at this time to predict what actions, if any, that the NERC may take based on the data submittals or interview results.
On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. ReliabilityFirst issued an Initial Notice of Alleged Violation on June 22, 2009. The NERC approved FirstEnergy’s mitigation plan on August 19, 2009, and submitted it to the FERC for approval on August 19, 2009. FirstEnergy is not able at this time to predict what actions or penalties, if any, that ReliabilityFirst will propose for this self-report of violation.
Ohio(Applicable to OE, CEI, TE and FES)
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009.2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter.matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan then in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh.KWH. The power supply obtained through this process providesprovided generation service to the Ohio Companies’ retail customers who choosechose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OEdenied OE’s and TETE’s request to continue collecting RTC orand denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery ofrecovered the increased purchased power costs for OE and TE, and authorizes CEI to collectrecovered a portion of those costs currently and deferfor CEI, with the remainder being deferred for future recovery.
On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP providesprovided that generation willwould be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices willwould be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further providesprovided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI willwould agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies willwould collect a delivery service improvement rider at an overall average rate of $.002 per kWhKWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressesaddressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation taketook effect on April 1, 2009 while the remaining provisions taketook effect on June 1, 2009. The CBP auction is currently scheduled
On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 13, 2009. The bidding will occur for a single, two-year product2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and there will not be a load cap for the bidders. FES may participate without limitation. $140.1 million being recovered from non-residential customers.
The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.
SB221 also requires electric distribution utilities to implement energy efficiency programs thatprograms. Under the provisions of SB221, the Ohio Companies are required to achieve ana total annual energy savings equivalent of 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 2013.2013, with additional savings required through 2025. Utilities are also required to reduce peak demand in 2009 by one percent,1%, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. CostsThe PUCO may amend these benchmarks in certain, limited circumstances. Additionally, 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 serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance arewill be recoverable from customers.
On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised.
On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 related to the employment of alternative energy resources, energy efficiency/peak demand reduction programs as well as greenhouse gas reporting requirements and changes to long term forecast reporting requirements. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.
In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011.
On October 20, 2009, the Ohio Companies filed an MRO to procure electric generation service for the period beginning June 1, 2011. The proposed MRO would establish a CBP to secure generation supply for customers who do not shop with an alternative supplier and would be similar, in all material respects, to the CBP conducted in May 2009 in that it would procure energy, capacity and certain transmission services on a slice of system basis. However, unlike the May 2009 CBP, the MRO would include multiple bidding sessions and multiple products with different delivery periods for generation supply designed to reduce potential volatility, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP Pennsylvania(Applicable to FES, Met-Ed, Penelec, OE and Penn)
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. The TSCs included a component for under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010. Various intervenorsinterveners filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded andconcluded. On August 11, 2009, the companies are awaitingALJ issued a Recommended Decision fromto the ALJ. ThePPUC approving Met-Ed’s and Penelec’s TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 millionas filed and Penelec - $4 million)dismissing all complaints. Exceptions by various interveners were filed and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCsreply exceptions were filed by December 31, 2010.
On April 15, 2009, Met-Ed and Penelec filed revised TSCs withPenelec. The Companies are now awaiting a PPUC decision. On May 28, 2009, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers the new TSC would resultresulted in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increaseincreased to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposingthe PPUC approved Met-Ed’s proposal to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs intoto a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The billAct 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart metersmeters; and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.
Major provisions of the legislation include:
· | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a prudent mix of long-term and short-term contracts and spot market purchases; |
· | the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; |
· | utilities must provide for the installation of smart meter technology within 15 years; |
· | utilities must reduce peak demand by a minimum reduction in peak demand of 4.5% by May 31, 2013; |
· | minimum reductions inutilities must reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and |
· | an expandedthe definition of alternative energyAlternative Energy was expanded to include additional types of hydroelectric and biomass facilities. |
Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On July 1, 2009, Met-Ed, Penelec, and Penn filed EE&C Plans with the PPUC in accordance with Act 129. The Pennsylvania Companies submitted a supplemental filing on July 31, 2009, to revise the Total Resource Cost test items in the EE&C Plans pursuant to the PPUC’s June 23, 2009 Order. Following an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved in part, and rejected in part, the Pennsylvania Companies’ filing. The Companies must file revised – EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.
Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year.
Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requestedanticipate PPUC approval of their plan byin November 2009.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filingfiling to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51$59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.” In response to the Tentative Order comments were filed by the Office of Small Business Advocate, Office of Consumer Advocate, York County Solid Waste and Refuse Authority, ARIPPA, the Met-Ed Industrial Users Group and Penelec Industrial Customer Alliance objecting to the above accounting method utilized by Met-Ed and Penelec. The PPUC must actCompanies filed reply comments on this filing within 120 days.October 26, 2009, and await the decision of the PPUC.
New Jersey (Applicable to JCP&L)
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31,September 30, 2009, the accumulated deferred cost balance totaled approximately $165$102 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Following public hearing and consideration of comments from interested parties, the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact JCP&L.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.
The EMP was issued on October 22, 2008, establishing five major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. Such utility specific plans are due to be filed with the BPU by July 1, 2010. At this time, JCP&LFirstEnergy cannot determine the impact, if any, the EMP may have on itstheir operations.
In support of the New Jersey Governor’sGovernor's Economic Assistance and Recovery Plan, JCP&L announced its intenta proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. AnUnder the proposal, an estimated $40 million willwould be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. ApproximatelyIn addition, approximately $34 million willwould be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million willwould be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million willwould be spent on energy efficiency programs that willwould complement those currently being offered. CompletionThe project relating to expansion of the existing demand response programs was approved by the BPU on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.the proposal.
FERC Matters(Applicable to FES and each of the Utilities)
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.
PJM Transmission Rate
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design;design, notably AEP, which proposed to create a "postage stamp",stamp," or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. ThisAEP's proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order ("Opinion 494") finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral argument wasarguments were held on April 13, 2009, and2009. The Seventh Circuit Court of Appeals issued a decision is expected this summer.on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion electric Cooperative was denied by the Seventh Circuit on October 20, 2009.
The FERC’s orders on PJM rate design will preventprevented the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reducereduces the costscost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Order 494 appeal discussed above.
Duquesne’s Request to Withdraw from PJMRTO Consolidation
On November 8, 2007, Duquesne Light Company (Duquesne)August 17, 2009, FirstEnergy filed a requestan application with the FERC requesting to exitconsolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and to join MISO. Duquesne’s proposed moveThe consolidation would affect numerous FirstEnergy interests, including but not limited tomake the terms under whichtransmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s Beaver Valley Plant would continue to participatetransmission assets in PJM’s energy markets. FirstEnergy, therefore, intervenedPennsylvania and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.transmission assets in New Jersey already operate as a part of PJM.
In November, 2008, Duquesne and other parties, includingTo ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy negotiatedfiled a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meetrelated complaint with FERC on the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolutionissue of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in oppositionallocating transmission costs to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.
FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on June 1, 2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.
On September 4, 2009, the PUCO opened a case to take comments from Ohio stakeholders regarding the RTO consolidation. FirstEnergy filed extensive comments in the PUCO case on September 25, 2009 and reply comments on October 13, 2009 and attended a public hearing on September 15, 2009 to respond to questions regarding the RTO consolidation.
Several parties have intervened in the regulatory dockets at the FERC and at the PUCO. Certain interveners have commented and protested particular elements of the proposed RTO consolidation, including an exit fee to MISO, integration costs to PJM, and cost-allocations of future transmission upgrades in PJM and MISO. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks.discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties have filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.
PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes, which provide for incremental improvements to the RPM, will be effective November 1, 2009, pending FERC approval. In addition, the FERC has indefinitely postponedCMEC continues to work to address additional compliance items directed by the technical conference on RPM granted in the FERC order of September 19, 2008.March 26, 2009 Order. Another compliance filing is due December 1, 2009.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement iswas proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.
On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to startwas implemented as planned effectiveon June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.
FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of thea December 23, 2008 waiver.waiver of restrictions on affiliate sales without prior approval of the FERC.
On OctoberMay 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, 2009, and continuing through May 31, 2008,2011.
On November 3, 2009, FES, executed a ThirdMet-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limitscontinues to limit the amount of capacity and energyresources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements.Under the new agreement, Met-Ed, Penelec, and Waverly have committed resourcesassign 1300 MW of existing energy purchases to FES to assist it in place for the balance of their expectedsupplying Buyers’ power supply during 2009requirements and 2010. Undermanaging congestion expenses. FES can either sell the Third Restated Partial Requirements Agreement, Met-Ed, assigned power from the third party into the market or use it to serve the Met-Ed/Penelec and Waverly areload. FES is responsible for obtaining additional power supply requirements created bysupplies in the default orevent of failure of supply of their committed resources.the assigned energy purchase contracts. Prices for the power providedsold by FES were not changedincreased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the ThirdFourth Restated Partial Requirements Agreement.
Environmental Matters
Various federal, state and local authorities regulate FES and the Utilities with regard to air and water quality and other environmental matters. The effects of compliance on FES and the Utilities with regard to environmental matters could have a material adverse effect on their earnings and competitive position to the extent that they compete 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.
FES and the Utilities accrue environmental liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FES’ and the Utilities’ determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance (Applicable to FES, OE, JCP&L, Met-Ed and Penelec)
FES is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FES believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FES has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FES complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FES' facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FES believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissionsFourth Restated Partial Requirements Agreement terminates at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installationend of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints. The Pennsylvania Department of Health and the U.S. Agency for Toxic Substance and Disease Registry recently disclosed their intention to conduct additional air monitoring in the vicinity of the Mansfield plant.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. Specifically, New Jersey alleges that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeks injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint on February 19, 2009. On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fully comply with the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter.
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards (Applicable to FES)
In March 2005, the EPA finalized the CAIR covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. The future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.2010.
Mercury Emissions (Applicable to FES)
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. The EPA is developing new mercury emission standards for coal-fired power plants. FGCO’s future cost of compliance with mercury regulations may be substantial and will depend on the action taken by the EPA and on how they are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant, FES’ only Pennsylvania coal-fired power plant, until 2015, if at all.
Climate Change (Applicable to FES)
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing the amount of man-made GHG, including CO2, emitted by developed countries by 2012. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, the EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity in the United States comes from renewable sources by 2012, and increasing to 25% by 2025; and implementing an economy-wide cap-and-trade program to reduce GHG emissions 80% by 2050.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee has passed one such bill. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.
FES cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions could require significant capital and other expenditures. The CO2 emissions per KWH of electricity generated by FES is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act (Applicable to FES)
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FES' plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FES' operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, 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 large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’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. FES is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal (Applicable to FES and each of the Utilities)
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. The future cost of compliance with coal combustion waste regulations may be substantial and will depend, in part, on the regulatory action taken by the EPA and implementation by the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheet as of March 31, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91 million (JCP&L - - $64 million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million) have been accrued through March 31, 2009. Included in the total are accrued liabilities of approximately $56 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
Other Legal Proceedings
Power Outages and Related Litigation (Applicable to JCP&L)
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding, the Muise class action) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising from the July 1999 service interruptions in the JCP&L territory.
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. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed their appeal to the trial court's decision to decertify the class.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt of JCP&L’s response to NERC’s data request.
Nuclear Plant Matters (Applicable to FES)
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.
In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008, the NRC issued a draft supplemental Environmental Impact Statement for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station in 2009. If renewed licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would be extended until 2036 and 2047 for Units 1 and 2, respectively.
Other Legal Matters (Applicable to FES and each of the Utilities)
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FES' and the Utilities’ normal business operations pending against them. The other potentially material items not otherwise discussed above are described below.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the appeal process could take as long as 24 months. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.
The union employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties are continuing to bargain with the assistance of a federal mediator. FES has a strike mitigation plan ready in the event of a strike.
The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation plan ready in the event of a strike.
FES and the Utilities accrue legal liabilities only when they conclude that it is probable that they have an obligation for such costs and can reasonably estimate the amount of such costs. If it were ultimately determined that FES and the Utilities have legal liability or are otherwise made subject to liability based on the above matters, it could have a material adverse effect on their financial condition, results of operations and cash flows.
New Accounting Standards and Interpretations (Applicable to FES and each of the Utilities)
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FES and the Utilities do not expect the FSP to have a material effect upon their financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009 and do not expect the FSP to have a material effect upon their financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FES and the Utilities will adopt the FSP for their interim period ending June 30, 2009, and expect to expand their disclosures regarding the fair value of financial instruments.
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSP is effective for fiscal years ending after December 15, 2009. FES and the Utilities will expand their disclosures related to postretirement benefit plan assets as a result of this FSP.
Recent Developments (Applicable to FES and each of the Utilities to the extent indicated)
On April 6, 2009, Richard H. Marsh, Senior Vice President and Chief Financial Officer (CFO) of FirstEnergy indicated his intention to step down as CFO on May 1, 2009, and retire from FirstEnergy effective July 1, 2009. Mr. Marsh was also Senior Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE. On April 8, 2009, FirstEnergy’s Board of Directors elected Mark T. Clark, Executive Vice President and CFO to succeed Mr. Marsh as CFO of FirstEnergy, effective May 1, 2009. Mr. Clark also became Executive Vice President and CFO of FES and each of the Utilities except JCP&L and a Director of FES, OE, CEI and TE, effective May 1, 2009.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. ORGANIZATION AND BASIS OF PRESENTATION
FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, FES and its subsidiaries FGCO and NGC, and FESC.
FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.
These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, 2008 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.
FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 6) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) 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.
The consolidated financial statements as of March 31, 2009, and for the three-month periods ended March 31, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated May 7, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a “report” or a “part” of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.
2. EARNINGS PER SHARE
Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:
Reconciliation of Basic and Diluted | | Three Months Ended March 31 | | Earnings per Share of Common Stock | | 2009 | | 2008 | | | (In millions, except per share amounts) | Earnings available to parent | | $ | 119 | | $ | 276 | | | | | | | | | | Average shares of common stock outstanding – Basic | | | 304 | | | 304 | | Assumed exercise of dilutive stock options and awards | | | 2 | | | 3 | | Average shares of common stock outstanding – Diluted | | | 306 | | | 307 | | | | | | | | | | Basic earnings per share of common stock | | $ | 0.39 | | $ | 0.91 | | Diluted earnings per share of common stock | | $ | 0.39 | | $ | 0.90 | |
3. FAIR VALUE MEASURES
FirstEnergy’s valuation techniques, including the three levels of the fair value hierarchy as defined by SFAS 157, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy’s Annual Report.
The following table sets forth FirstEnergy’s financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of March 31, 2009 and December 31, 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.
Recurring Fair Value Measures | | | | | | | | | | as of March 31, 2009 | | Level 1 | | Level 2 | | Level 3 | | Total | | | | (In millions) | | Assets: | | | | | | | | | | | | | | Derivatives | | $ | - | | $ | 43 | | $ | - | | $ | 43 | | Available-for-sale securities(1) | | | 427 | | | 1,533 | | | - | | | 1,960 | | NUG contracts(2) | | | - | | | - | | | 340 | | | 340 | | Other investments | | | - | | | 80 | | | - | | | 80 | | Total | | $ | 427 | | $ | 1,656 | | $ | 340 | | $ | 2,423 | | | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | Derivatives | | $ | 30 | | $ | 27 | | $ | - | | $ | 57 | | NUG contracts(2) | | | - | | | - | | | 816 | | | 816 | | Total | | $ | 30 | | $ | 27 | | $ | 816 | | $ | 873 | |
(1)
| Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts.
Balance excludes $3 million of receivables, payables and accrued income.
|
(2)
| NUG contracts are completely offset by regulatory assets. |
Recurring Fair Value Measures | | | | | | | | | | as of December 31, 2008 | | Level 1 | | Level 2 | | Level 3 | | Total | | | | (In millions) | | Assets: | | | | | | | | | | | | | | Derivatives | | $ | - | | $ | 40 | | $ | - | | $ | 40 | | Available-for-sale securities(1) | | | 537 | | | 1,464 | | | - | | | 2,001 | | NUG contracts(2) | | | - | | | - | | | 434 | | | 434 | | Other investments | | | - | | | 83 | | | - | | | 83 | | Total | | $ | 537 | | $ | 1,587 | | $ | 434 | | $ | 2,558 | | | | | | | | | | | | | | | | Liabilities: | | | | | | | | | | | | | | Derivatives | | $ | 25 | | $ | 31 | | $ | - | | $ | 56 | | NUG contracts(2) | | | - | | | - | | | 766 | | | 766 | | Total | | $ | 25 | | $ | 31 | | $ | 766 | | $ | 822 | |
| (1) | Primarily consists of investments in nuclear decommissioning trusts, the spent nuclear fuel trusts and the NUG trusts.
Balance excludes $5 million of receivables, payables and accrued income.
|
(2) NUG contracts are completely offset by regulatory assets.
The determination of the above fair value measures takes into consideration various factors required under SFAS 157. These factors include nonperformance risk, including counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of nonperformance risk was immaterial in the fair value measurements.
The following table sets forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three months ended March 31, 2009 and 2008 (in millions):
| | Three Months Ended March 31 | | | | 2009 | | 2008 | | Balance as of January 1 | | $ | (332 | ) | $ | (803 | ) | Settlements(1) | | | 83 | | | 64 | | Unrealized gains (losses)(1) | | | (227 | ) | | 320 | | Net transfers to (from) Level 3 | | | - | | | - | | Balance as of March 31, 2009 | | $ | (476 | ) | $ | (419 | ) | | | | | | | | | Change in unrealized gains (losses) relating to | | | | | | | | instruments held as of March 31 | | $ | (227 | ) | $ | 320 | | | | | | | | | | (1) Changes in the fair value of NUG contracts are completely offset by regulatory assets and do not impact earnings. | |
On January 1, 2009, FirstEnergy adopted FSP FAS 157-2, for financial assets and financial liabilities measured at fair value on a non-recurring basis. The impact of SFAS 157 on those financial assets and financial liabilities is immaterial.
4. 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 uses a variety of derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used for risk management purposes. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties. FirstEnergy's Risk Policy Committee, comprised of members of senior management, provides general management oversight for risk management activities throughout FirstEnergy. They are responsible for promoting the effective design and implementation of sound risk management programs. They also oversee compliance with corporate risk management policies and established risk management practices.
FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheet at their fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are recorded as other expense, as AOCL, or as part of the value of the hedged item as described below.
Interest Rate Derivatives
Under the revolving credit facility, FirstEnergy incurs variable interest charges based on LIBOR. In 2008, FirstEnergy entered into swaps with a notional value of $200 million to hedge against changes in associated interest rates. Hedges with a notional value of $100 million expire in November 2009 and the remainder expire in November 2010. The swaps are accounted for as cash flow hedges under SFAS 133. As of March 31, 2009, the fair value of outstanding swaps was $(4) million.
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 treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the first quarter of 2009, FirstEnergy terminated forward swaps with a notional value of $100 million when a subsidiary issued long term debt. The gain associated with the termination was $1.3 million, of which $0.3 million was ineffective and recognized as an adjustment to interest expense. The remaining effective portion will be amortized to interest expense over the life of the hedged debt. FirstEnergy currently has no outstanding forward swaps.
As of March 31, 2009 and 2008, the total fair value of outstanding interest rate derivatives was $(4) million and $(3) million, respectively. Interest rate derivatives are located in “Other Noncurrent Liabilities” in FirstEnergy’s consolidated balance sheets. The effect of interest rate derivatives on the statements of income and comprehensive income during the periods ended March 31, 2009 and 2008 were:
| Three Months Ended | | | | | | | | 2009 | | | 2008 | | Effective Portion | | (in millions) | | | | Loss Recognized in AOCL | $ | (2 | ) | $ | - | | | Loss Reclassified from AOCL into Interest Expense | | (5 | ) | | (4 | ) | Ineffective Portion | | | | | | | | Loss Recognized in Interest Expense | | - | | | (1 | ) |
Total unamortized losses included in AOCL associated with prior interest rate hedges totaled $119 million ($70 million net of tax) as of March 31, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.
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 in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s maximum hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.
The following tables summarize the location and fair value of commodity derivatives in FirstEnergy’s consolidated balance sheets:
Derivative Assets | | Derivative Liabilities | | | Fair Value | | | | Fair Value | | | March 31, | | December 31, | | | | March 31, | | December 31, | | | 2009 | | 2008 | | | | 2009 | | 2008 | Cash Flow Hedges | | (in millions) | | Cash Flow Hedges | | (in millions) | Electricity Forwards | | | | | | Electricity Forwards | | | | | | Current Assets | $ | 23 | $ | 11 | | | Current Liabilities | $ | 23 | $ | 27 | Natural Gas Futures | | | | | | Natural Gas Futures | | | | | | Current Assets | | - | | - | | | Current Liabilities | | 11 | | 4 | | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 5 | | 5 | Other | | | | | | Other | | | | | | Current Assets | | - | | - | | | Current Liabilities | | 10 | | 12 | | Long-Term Deferred Charges | | - | | - | | | Noncurrent Liabilities | | 3 | | 4 | | | $ | 23 | $ | 11 | | | $ | 52 | $ | 52 |
| | | | | | | | Derivative Assets | | Derivative Liabilities | | | | Fair Value | | | | Fair Value | | | | March 31, 2009 | | December 31, 2008 | | | | March 31, 2009 | | December 31, 2008 | Economic Hedges | | (in millions) | | Economic Hedges | | (in millions) | NUG Contracts | | | | NUG Contracts | | | | Power Purchase | $ | 340 | $ | 434 | | | Power Purchase | $ | 816 | $ | 766 | | Contract Asset | | | | | | | Contract Liability | | | | | Other | | | | | | Other | | | | | | Current Assets | | 1 | | 1 | | | Current Liabilities | | 1 | | 1 | | Long-Term Deferred Charges | | 19 | | 28 | | | Noncurrent Liabilities | | - | | - | | | $ | 360 | $ | 463 | | | $ | 817 | $ | 767 | Total Commodity Derivatives | $ | 383 | $ | 474 | | Total Commodity Derivatives | $ | 869 | $ | 819 |
Electricity forwards are used to balance expected retail and wholesale sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas, primarily used in FirstEnergy’s peaking units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs. The following table summarizes the volume of FirstEnergy’s outstanding derivative transactions as of March 31, 2009.
| Purchases | | Sales | | Net | | Units | | | | (in thousands) | | Electricity Forwards | | 772 | | | (1,735 | ) | | (963 | ) | | MWh | | Heating Oil Futures | | 20,496 | | | (2,520 | ) | | 17,976 | | | Gallons | | Natural Gas Futures | | 4,850 | | | - | | | 4,850 | | | mmBtu | |
The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three months ended March 31, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:
Derivatives in Cash Flow Hedging Relationships | Electricity | | | Natural Gas | | | Heating Oil | | | | | | | Forwards | | | Futures | | | Futures | | | Total | | 2009 | | (in millions) | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (2 | ) | $ | (7 | ) | $ | (1 | ) | $ | (10 | ) | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | Purchased Power Expense | | (18 | ) | | - | | | - | | | (18 | ) | | Fuel Expense | | - | | | - | | | (4 | ) | | (4 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2008 | | | | | | | | | | | | | Gain (Loss) Recognized in AOCL (Effective Portion) | $ | (14 | ) | $ | 3 | | $ | - | | $ | (11 | ) | Effective Gain (Loss) Reclassified to:(1) | | | | | | | | | | | | | Purchased Power Expense | | (17 | ) | | - | | | - | | | (17 | ) | | Fuel Expense | | - | | | - | | | - | | | | | | | | | | | | | | | | | | (1) The ineffective portion was immaterial. | | | | | | | | | | | | |
Derivatives Not in Hedging Relationships | NUG | | | | | | | | | | | Contracts | | | Other | | | Total | | 2009 | | (in millions) | Unrealized Gain (Loss) Recognized in: | | | | | | | | | | Regulatory Assets(1) | $ | (227 | ) | $ | - | | $ | (227 | ) | Realized Gain (Loss) Reclassified to: | | | | | | | | | | | Fuel Expense(2) | | $ | - | | $ | (1 | ) | $ | (1 | ) | Regulatory Assets(3) | | | (83 | ) | | 10 | | | (73 | ) | | | $ | (83 | ) | $ | 9 | | $ | (74 | ) | 2008 | | | | | | | | | | | Unrealized Gain (Loss) Recognized in: | | | | | | | | | | Regulatory Assets(1) | $ | 320 | | $ | - | | $ | 320 | | | | | | | | | | | | Realized Gain (Loss) Reclassified to: | | | | | | | | | | | | Regulatory Assets(3) | $ | (64 | ) | $ | 11 | | $ | (53 | ) | | | | | | | | | | | | | (1) | Changes in the fair value of NUG Contracts are deferred for future recovery from (or refund to) customers. | (2) | The realized gain (loss) is reclassified upon termination of the derivative instrument | (3) | The above market cost of NUG power is deferred for future recovery from (or refund to) customers. |
Total unamortized losses included in AOCL associated with commodity derivatives were $32 million ($19 million net of tax) as of March 31, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The change (net of tax) resulted from a net $5 million increase related to current hedging activity and a $13 million decrease due to net hedge losses reclassified to earnings during the first quarter of 2009. Based on current estimates, approximately $15 million (after tax) of the net deferred losses on derivative instruments in AOCL as of March 31, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.
Many of FirstEnergy’s commodity derivatives contain credit risk features. As of March 31, 2009, FirstEnergy posted $141 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit-risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit-risk related contingent features that are in a liability position on March 31, 2009 was $4 million, for which no collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $4 million of additional collateral related to commodity derivatives.
5. PENSION AND OTHER POSTRETIREMENT BENEFITS
FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31. FirstEnergy also 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 available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.
For the three months ended March 31, 2009 and 2008, FirstEnergy’s net pension and OPEB expense (benefit) was $43 million and $(15) million, respectively. The components of FirstEnergy's net pension and other postretirement benefit cost (including amounts capitalized) for the three months ended March 31, 2009 and 2008, consisted of the following:
| | Pension Benefits | | Other Postretirement Benefits | | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Expected return on plan assets | | | | | | | | | | | | | | Amortization of prior service cost | | | | | | | | | | | | | | Recognized net actuarial loss | | | | | | | | | | | | | | Net periodic cost (credit) | | | | | | | ) | | | ) | | | ) |
Pension and postretirement benefit obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The Companies capitalize employee benefits related to construction projects. The net pension and other postretirement benefit costs (including amounts capitalized) recognized by each of the Companies for the three months ended March 31, 2009 and 2008 were as follows:
| | Pension Benefit Cost (Credit) | | Other Postretirement Benefit Cost (Credit) | | | | 2009 | | 2008 | | 2009 | | 2008 | | | | (In millions) | | | | | | | | | | | | ) | | | ) | | | | | | | | ) | | | ) | | | ) | | | | | | | | ) | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | ) | | | | | | | | | | | | | | ) | Other FirstEnergy subsidiaries | | | | | | | | | | | | | ) | | | | | | | | ) | | | ) | | | ) |
6. VARIABLE INTEREST ENTITIES
FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by FIN 46R. Effective January 1, 2009, FirstEnergy adopted SFAS 160. As a result, FirstEnergy and its subsidiaries reflect the portion of VIEs not owned by them in the caption noncontrolling interest within the consolidated financial statements. The change in noncontrolling interest within the Consolidated Balance Sheets is the result of earnings and losses of the noncontrolling interests and distributions to owners.
Mining Operations
On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million (of which $1.7 million was paid in March 2009) to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests will remain unchanged after the sale is completed in July 2009. Effective January 16, 2010, the joint venture will have 18 months to exercise an option to acquire the remaining 20% stake in the mining operations. In accordance with FIN 46R, FEV consolidates the mining and transportation operations of this joint venture in its financial statements.
Trusts
FirstEnergy’s consolidated financial statements include PNBV and Shippingport, VIEs created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.
PNBV was established to purchase a portion of the lease obligation bonds issued in connection with OE’s 1987 sale and leaseback of its interests in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase all of the lease obligation bonds issued in connection with CEI’s and TE’s Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.
Loss Contingencies
FES and the Ohio Companies are exposed to losses under their applicable sale-leaseback agreements upon the occurrence of certain contingent events that each company considers unlikely to occur. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events that render the applicable plant worthless. Net discounted lease payments would not be payable if the casualty loss payments were made. The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above:
| | Maximum Exposure | | Discounted Lease Payments, net(1) | | Net Exposure | | | (In millions) | FES | | $ | 1,373 | | $ | 1,202 | | $ | 171 | OE | | 759 | | 587 | | 172 | CEI | | 740 | | 73 | | 667 | TE | | 740 | | 419 | | 321 |
| (1) The net present value of FirstEnergy’s consolidated sale and leaseback operating
lease commitments is $1.7 billion
|
In October 2007, CEI and TE assigned their leasehold interests in the Bruce Mansfield Plant to FGCO. FGCO assumed all of CEI’s and TE’s obligations arising under those leases. FGCO subsequently transferred the Unit 1 portion of these leasehold interests, as well as FGCO’s leasehold interests under its July 2007 Bruce Mansfield Unit 1 sale and leaseback transaction to a newly formed wholly-owned subsidiary in December 2007. The subsidiary assumed all of the lessee obligations associated with the assigned interests. However, CEI and TE remain primarily liable on the 1987 leases and related agreements as to the lessors and other parties to the agreements. FGCO remains primarily liable on the 2007 leases and related agreements, and FES remains primarily liable as a guarantor under the related 2007 guarantees, as to the lessors and other parties to the respective agreements. These assignments terminate automatically upon the termination of the underlying leases.
During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.
Power Purchase Agreements
In accordance with FIN 46R, FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Companies and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 24 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.
FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of FIN 46R. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. As required by FIN 46R, FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities under FIN 46R.
Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs to be recovered from customers. Purchased power costs from these entities during the three months ended March 31, 2009 and 2008 are shown in the following table:
| | Three Months Ended | | | | March 31, | | | | 2009 | | 2008 | | | | (In millions) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Transition Bonds
The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS.
JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of March 31, 2009, $363 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consists primarily of bondable transition property.
Bondable transition property represents the irrevocable right under New Jersey law of a utility company to charge, collect and receive from its customers, through a non-bypassable TBC, the principal amount and interest on transition bonds and other fees and expenses associated with their issuance. JCP&L sold its bondable transition property to JCP&L Transition Funding and JCP&L Transition Funding II and, as servicer, manages and administers the bondable transition property, including the billing, collection and remittance of the TBC, pursuant to separate servicing agreements with JCP&L Transition Funding and JCP&L Transition Funding II. For the two series of transition bonds, JCP&L is entitled to aggregate quarterly servicing fees of $157,000 payable from TBC collections.
7. INCOME TAXES
FirstEnergy accounts for uncertainty in income taxes recognized in a company’s financial statements in accordance with FIN 48. This interpretation 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. Upon completion of the federal tax examination for the 2007 tax year in the first quarter of 2009, FirstEnergy recognized $13 million in tax benefits, which favorably affected FirstEnergy’s effective tax rate. During the first three months of 2008, there were no material changes to FirstEnergy’s unrecognized tax benefits. As of March 31, 2009, FirstEnergy expects that it is reasonably possible that $193 million of the unrecognized benefits may be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.
FIN 48 also requires companies to recognize 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 in accordance with FIN 48 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 net amount of accumulated interest accrued as of March 31, 2009 was $61 million, as compared to $59 million as of December 31, 2008. During the first three months of 2009 and 2008, there were no material changes to the amount of interest accrued.
FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state tax authorities. All state jurisdictions are open from 2001-2008. The IRS began reviewing returns for the years 2001-2003 in July 2004 and several items are under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. 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.
8. COMMITMENTS, GUARANTEES AND CONTINGENCIES
(A) GUARANTEES AND OTHER ASSURANCES
As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of March 31, 2009, outstanding guarantees and other assurances aggregated approximately $4.5 billion, consisting of parental guarantees - $1.2 billion, subsidiaries’ guarantees - $2.6 billion, surety bonds - $0.1 billion and LOCs - $0.6 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 obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $1.2 billion discussed above) as of March 31, 2009 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 March 31, 2009, FirstEnergy's maximum exposure under these collateral provisions was $761 million, consisting of $55 million due to “material adverse event” contractual clauses and $706 million due to a below investment grade credit rating. 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 $830 million, consisting of $54 million due to “material adverse event” contractual clauses and $776 million due to a below investment grade credit rating.
Most of FirstEnergy's surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $111 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.
In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of March 31, 2009, and forward prices as of that date, FES had $205 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $77 million. Depending on the volume of forward contracts entered and future price movements, FES could be required to post significantly higher amounts for margining.
In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally guaranteed all of FGCO’s obligations under each of the leases (see Note 12). 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.
On October 8, 2008, to enhance their liquidity position in the face of the turbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300 million secured term loan facility with Credit Suisse. Under the facility, FGCO is the borrower and FES and FirstEnergy are guarantors. Generally, the facility is available to FGCO until October 7, 2009, with a minimum borrowing amount of $100 million and maturity 30 days from the date of the borrowing. Once repaid, borrowings may not be re-borrowed.
(B) | ENVIRONMENTAL MATTERS |
Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it 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. FirstEnergy estimates capital expenditures for environmental compliance of approximately $808$800 million for the period 2009-2013.
FirstEnergy accrues environmental liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. Unasserted claims are reflected in FirstEnergy’s determination of environmental liabilities and are accrued in the period that they become both probable and reasonably estimable.
Clean Air Act Compliance
FirstEnergy is required to meet federally-approved SO2 emissions regulations. Violations of such regulations can result in the shutdown of the generating unit involved and/or civil or criminal penalties of up to $37,500 for each day the unit is in violation. The EPA has an interim enforcement policy for SO2 regulations in Ohio that allows for compliance based on a 30-day averaging period. FirstEnergy believes it is currently in compliance with this policy, but cannot predict what action the EPA may take in the future with respect to the interim enforcement policy.
The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore Power Plant dated June 15, 2006, alleging violations to various sections of the CAA. FirstEnergy has disputed those alleged violations based on its CAA permit, the Ohio SIP and other information provided to the EPA at an August 2006 meeting with the EPA. The EPA has several enforcement options (administrative compliance order, administrative penalty order, and/or judicial, civil or criminal action) and has indicated that such option may depend on the time needed to achieve and demonstrate compliance with the rules alleged to have been violated. On June 5, 2007, the EPA requested another meeting to discuss “an appropriate compliance program” and a disagreement regarding emission limits applicable to the common stack for Bay Shore Units 2, 3 and 4.
FirstEnergy complies with SO2 reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NOX reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX reductions at FirstEnergy's facilities. The EPA's NOX Transport Rule imposes uniform reductions of NOX emissions (an approximate 85% reduction in utility plant NOX emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NOX emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NOX budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.
In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).
On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. On January 11, 2008, FirstEnergy filed a motion to dismiss claims alleging a public nuisance. On April 24, 2008, the Court denied the motion to dismiss, but also ruled that monetary damages could not be recovered under the public nuisance claim. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a settlement of the PennFuture complaint was reached with PennFuture and one of the three individual complaintants. On October 16, 2009, the Court approved the settlement and dismissed the claims of PennFuture and of the settling individual complaintant. The other two non-settling complaintants are now represented by counsel handling the three cases filed in July 2008. FGCO believes thethose claims are without merit and intends to defend itself against the allegations made in thesethose three complaints. The Pennsylvania Department of Health, andunder a Cooperative Agreement with the U.S. Agency for Toxic SubstanceSubstances and Disease Registry, recently disclosed their intentioncompleted a Health Consultation regarding the Mansfield Plant and issued a report dated March 31, 2009 which concluded there is insufficient sampling data to conductdetermine if any public health threat exists for area residents due to emissions from the Mansfield Plant. The report recommended additional air monitoring and sample analysis in the vicinity of the Mansfield plant.Plant, which the Pennsylvania Department of Environmental Protection has completed.
On December 18, 2007, the state of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allegesallege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seeksseek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. On March 14, 2008, Met-Ed filed a motion to dismiss the citizen suit claims against it and a stipulation in which the parties agreed that GPU, Inc. should be dismissed from this case. On March 26, 2008, GPU, Inc. was dismissed by the United States District Court. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009. 2009, and on September 30, 2009, respectively. 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 on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.
On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.
On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.
On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”), and Title V regulations at the Eastlake, Lakeshore, Bay Shore, and Ashtabula generating plants. The EPA’s NOV alleges equipment replacements occurring during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. On September 15, 2009, FGCO received an additional information request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provisions of the CAA. FGCO intends to fully comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 15, 2006 finding of violation and NOV in which EPA alleged CAA violations at the Bay Shore Generating Plant remains unresolved and FGCO is unable to predict the outcome of such matter.
On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.
National Ambient Air Quality Standards
In March 2005, the EPA finalized the CAIR, covering a total of 28 states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia, based on proposed findings that air emissions from 28 eastern states and the District of Columbia significantly contribute to non-attainment of the NAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to just 2.5 million tons annually and NOX emissions to just 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. TheOn July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX 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. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.
Mercury Emissions
In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized the CAMR, which provides a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" from implementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15 tons per year by 2018. Several states and environmental groups appealed the CAMR to the United States Court of Appeals for the District of Columbia. On February 8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. TheOn October 21, 2009, the EPA is developing newopened a 30-day comment period on a proposed consent decree that would obligate the EPA to propose maximum achievable control technology (MACT) regulations for mercury emission standards for coal-fired power plants.and other hazardous air pollutants by March 16, 2011, and to finalize the regulations by November 16, 2011. FGCO’s future cost of compliance with mercuryMACT regulations may be substantial and will depend on the action taken by the EPA and on how theyany future regulations are ultimately implemented.
Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant FirstEnergy’s(FirstEnergy’s only Pennsylvania coal-fired power plant,plant) until 2015, if at all.
Climate Change
In December 1997, delegates to the United Nations' climate summit in Japan adopted an agreement, the Kyoto Protocol, to address global warming by reducing, by 2012, the amount of man-made GHG, including CO2, emitted by developed countries by 2012.countries. The United States signed the Kyoto Protocol in 1998 but it was never submitted for ratification by the United States Senate. However, the Bush administration had committed the United States to a voluntary climate change strategy to reduce domestic GHG intensity – the ratio of emissions to economic output – by 18% through 2012. Also, in an April 16, 2008 speech, former President Bush set a policy goal of stopping the growth of GHG emissions by 2025, as the next step beyond the 2012 strategy. In addition, theThe EPACT established a Committee on Climate Change Technology to coordinate federal climate change activities and promote the development and deployment of GHG reducing technologies. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, ensuring that 10% of electricity used in the United States comes from renewable sources by 2012, and increasing to 25% by 2025;2025, and implementing an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050.
There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. At the international level, efforts to reach a new global agreement to reduce GHG emissions post-2012 have begun with the Bali Roadmap, which outlines a two-year process designed to lead to an agreement in 2009. At the federal level, members of Congress have introduced several bills seeking to reduce emissions of GHG in the United States, and the Senate Environment and Public Works Committee hasHouse of Representatives passed one such bill.bill, the American Clean Energy and Security Act of 2009, on June 26, 2009. The Senate continues to consider a number of measures to regulate GHG emissions. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.
On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources.sources, . On September 23, 2009, the EPA finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when Clean Air Act permits under the New Source Review and Title V operating permits programs would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.
On September 21, 2009, the U.S. Court of Appeals for the Second Circuit and on October 16, 2009, the U.S. Court of Appeals for the Fifth Circuit, reversed and remanded lower court decisions that had dismissed complaints alleging damage from GHG emissions on jurisdictional grounds. 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. Connecticut v. AEP, No. 05-5105-cv (2d Cir. 2009)(seeking injunctive relief only); Comer v. Murphy Oil USA, No. 07-6-756 (5th Cir. 2009)(seeking damages only), respectively. While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be affirmed, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.
FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO2 emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures.expenditures or result in changes to its operations. The CO2 emissions per KWH of electricity generated by FirstEnergy is lower than many regional competitors due to its diversified generation sources, which include low or non-CO2 emitting gas-fired and nuclear generators.
Clean Water Act
Various water quality regulations, the majority of which are the result of the federal Clean Water Act and its amendments, apply to FirstEnergy's plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to FirstEnergy's operations. As provided in the Clean Water Act, authority to grant federal National Pollutant Discharge Elimination System water discharge permits can be assumed by a state. Ohio, New Jersey and Pennsylvania have assumed such authority.
On September 7, 2004, 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 large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’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. FirstEnergyThe EPA will now take up consideration of the rule on remand and take further action consistent with the opinions of the Supreme Court and the Court of Appeals, including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010. The Courts’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements .FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.
The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it is considering prosecution under the Clean Water Act and the Migratory Bird Treaty Act for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plants which occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCO is unable to predict the outcome of this matter.
Regulation of Waste Disposal
As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, the EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes. The EPA is reviewing its previous determination that Federal regulation of coal ash as a hazardous waste is not appropriate. The EPA has indicated an intent to propose regulations regarding this issue by the end of the year. Additional regulations of fossil-fuel combustion waste products could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste regulations which may be promulgated could be substantial and willwould depend, in part, on the regulatory action taken by the EPA and implementation by the states.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of March 31, 2009, FirstEnergy had approximately $1.6 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy agreed to contribute another $80 million to these trusts by 2010. Consistent with NRC guidance, utilizing a “real” rate of return on these funds of approximately 2% over inflation, these trusts are expected to exceed the minimum decommissioning funding requirements set by the NRC. Conservatively, these estimates do not include any return that the trusts may earn over the 20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 as it relates to the timing of the decommissioning of TMI-2) seeks for these facilities.
The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheetconsolidated balance sheet as of March 31,September 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $91$104 million (JCP&L - - $64$77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy Corp. - $25$24 million) have been accrued through March 31,September 30, 2009. Included in the total are accrued liabilities of approximately $56$68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.
(C) OTHER LEGAL PROCEEDINGSOther Legal Proceedings
Power Outages and Related Litigation
In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L's territory. In an investigation into the causes of the outages and the reliability of the transmission and distribution systems of all four of New Jersey’s electric utilities, the NJBPU concluded that there was not a prima facie case demonstrating that, overall, JCP&L provided unsafe, inadequate or improper service to its customers. Two class action lawsuits (subsequently consolidated into a single proceeding, the Muise class action)proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages arising fromdue to the July 1999 service interruptions in the JCP&L territory.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. The class was decertified twice by the trial court, and appealed both times by the Plaintiffs, with the results being that: (1) the Appellate Division limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based on a common incident involving the failure of the bushings of two large transformers in the Red Bank substation which resulted in planned and unplanned outages in the area during a 2-3 day period, and (2) in March 2007, the Appellate Division remanded this matter back to the Trial Court to allow plaintiffs sufficient time to establish a damage model or individual proof of damages. Proceedings then continued at the trial court level and a case management conference with the presiding Judge was held on June 13, 2008. At that conference, counsel for the Plaintiffs stated his intent to drop his efforts to create a class-wide damage model and, instead of dismissing the class action, expressed his desire for a bifurcated trial on liability and damages. In response, JCP&L filed an objection to the plaintiffs’ proposed trial plan and another motion to decertify the class. On March 31, 2009, the trial court again granted JCP&L’s motion to decertify the class. On April 20, 2009, the Plaintiffs filed theira motion for leave to take an interlocutory appeal to the trial court's decision to decertify the class, which was granted by the Appellate Division on June 15, 2009. Plaintiffs filed their appellate brief on August 25, 2009, and JCP&L filed an opposition brief on September 25, 2009. On or about October 13, 2009, Plaintiffs filed their reply brief in further support of their appeal of the trial court's decision decertifying the class. JCP&L is now waiting for the Appellate Division to schedule the appeal for oral arguments.
Nuclear Plant Matters
On May 14, 2007, the Office of Enforcement of the NRC issued a Demand for Information to FENOC, following FENOC’s reply to an April 2, 2007 NRC request for information about two reports prepared by expert witnesses for an insurance arbitration (the insurance claim was subsequently withdrawn by FirstEnergy in December 2007) related to Davis-Besse. The NRC indicated that this information was needed for the NRC “to determine whether an Order or other action should be taken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC will continue to operate its licensed facilities in accordance with the terms of its licenses and the Commission’s regulations.” FENOC was directed to submit the information to the NRC within 30 days. On June 13, 2007, FENOC filed a response to the NRC’s Demand for Information reaffirming that it accepts full responsibility for the mistakes and omissions leading up to the damage to the reactor vessel head and that it remains committed to operating Davis-Besse and FirstEnergy’s other nuclear plants safely and responsibly. FENOC submitted a supplemental response clarifying certain aspects of the response to the NRC on July 16, 2007. The NRC issued a Confirmatory Order imposing these commitments on FENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC had completed all necessary actions required by the Confirmatory Order.
In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. The NRC is required by statute to provide an opportunity for members of the public to request a hearing on the application. No members of the public, however, requested a hearing on the Beaver Valley license renewal application. On September 24, 2008,November 5, 2009, the NRC issued a draft supplemental Environmental Impact Statementrenewed operating license for Beaver Valley. FENOC will continue to work with the NRC Staff as it completes its environmental and technical reviews of the license renewal application, and expects to obtain renewed licenses for the Beaver Valley Power Station, in 2009. If renewedUnits 1 and 2. The operating licenses are issued by the NRC, the Beaver Valley Power Station’s licenses would befor these facilities was extended until 2036 and 2047 for Units 1 and 2, respectively.
Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2009, FirstEnergy had approximately $1.9 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry, and TMI-2. As part of the application to the NRC to transfer the ownership of Davis-Besse, Beaver Valley and Perry to NGC in 2005, FirstEnergy provided an additional $80 million parental guarantee associated with the funding of decommissioning costs for these units and indicated that it planned to contribute an additional $80 million to these trusts by 2010. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. On October 20, 2009, FENOC received a request for additional information (RAI) from the NRC that questions FENOC's methodology for calculating the decommissioning obligations for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.
Other Legal Matters
There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FirstEnergy and its subsidiaries. The other potentially material items not otherwise discussed above are described below.
JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009; the2009. The appeal process could take as long as 24 months. The parties are participating in the federal court's mediation programs and have held private settlement discussions. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.
The unionbargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. The parties areOn July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009, and a voluntary retirement program was implemented on August 19, 2009. A federal mediator is continuing to bargain withassist the assistance ofparties in reaching a federal mediator.negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike. The union employees at Met-Ed have been working without a labor contract since May 1, 2009. The parties are continuing to bargain and FirstEnergy has a work continuation plan ready in the event of a strike.
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.
9. REGULATORY MATTERS
(A) RELIABILITY INITIATIVES
In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The mandatory reliability standards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC is charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of its responsibilities to eight regional entities, including ReliabilityFirst Corporation. All of FirstEnergy’s facilities are located within the ReliabilityFirst region. FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards.
FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, it is clear that the NERC, ReliabilityFirst and the FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with new or amended standards cannot be determined at this time. However, the 2005 amendments to the Federal Power Act provide that all prudent costs incurred to comply with the new reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties and thus have a material adverse effect on its financial condition, results of operations and cash flows.
In April 2007, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.
On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations, with customers in the affected area losing power. Power was restored to most customers within a few hours and to all customers within eleven hours. On December 16, 2008, JCP&L provided preliminary information about the event to certain regulatory agencies, including the NERC. On March 31, 2009, the NERC initiated a Compliance Violation Investigation in order to determine JCP&L’s contribution to the electrical event and to review any potential violation of NERC Reliability Standards associated with the event. The initial phase of the investigation requires JCP&L to respond to NERC’s request for factual data about the outage. JCP&L submitted its written response on May 1, 2009. JCP&L is not able at this time to predict what actions, if any, that NERC will take upon receipt of JCP&L’s response to NERC’s data request.
(B) OHIO
On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and will go into effect for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009.
SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their current rate plan in effect as allowed by the terms of SB221. On December 31, 2008, the Ohio Companies conducted a CBP for the procurement of electric generation for retail customers from January 5, 2009 through March 31, 2009. The average winning bid price was equivalent to a retail rate of 6.98 cents per kwh. The power supply obtained through this process provides generation service to the Ohio Companies’ retail customers who choose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but did not authorize OE and TE to continue collecting RTC or allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider allows for current recovery of the increased purchased power costs for OE and TE, and authorizes CEI to collect a portion of those costs currently and defer the remainder for future recovery.
On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provides that generation will be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices will be based upon the outcome of a descending clock CBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in a portion of any increase resulting from this CBP process by authorizing deferral of related purchased power costs, subject to specified limits. The Amended ESP further provides that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI will agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies will collect a delivery service improvement rider at an overall average rate of $.002 per kWh for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addresses a number of other issues, including but not limited to, rate design for various customer classes, resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation take effect on April 1, 2009 while the remaining provisions take effect on June 1, 2009. The CBP auction is currently scheduled to begin on May 13, 2009. The bidding will occur for a single, two-year product and there will not be a load cap for the bidders. FES may participate without limitation.
SB221 also requires electric distribution utilities to implement energy efficiency programs that achieve an energy savings equivalent of 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. Utilities are also required to reduce peak demand in 2009 by one percent, with an additional seventy-five hundredths of one percent reduction each year thereafter through 2018. Costs associated with compliance are recoverable from customers.
(C) PENNSYLVANIA
Met-Ed and Penelec purchase a portion of their PLR and default service requirements from FES through a fixed-price partial requirements wholesale power sales agreement. The agreement allows Met-Ed and Penelec to sell the output of NUG energy to the market and requires FES to provide energy at fixed prices to replace any NUG energy sold to the extent needed for Met-Ed and Penelec to satisfy their PLR and default service obligations. If Met-Ed and Penelec were to replace the entire FES supply at current market power prices without corresponding regulatory authorization to increase their generation prices to customers, each company would likely incur a significant increase in operating expenses and experience a material deterioration in credit quality metrics. Under such a scenario, each company's credit profile would no longer be expected to support an investment grade rating for their fixed income securities. If FES ultimately determines to terminate, reduce, or significantly modify the agreement prior to the expiration of Met-Ed’s and Penelec’s generation rate caps in 2010, timely regulatory relief is not likely to be granted by the PPUC. See FERC Matters below for a description of the Third Restated Partial Requirements Agreement, executed by the parties on October 31, 2008, that limits the amount of energy and capacity FES must supply to Met-Ed and Penelec. In the event of a third party supplier default, the increased costs to Met-Ed and Penelec could be material.
On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. Various intervenors filed complaints against those filings. In addition, the PPUC ordered an investigation to review the reasonableness of Met-Ed’s TSC, while at the same time allowing Met-Ed to implement the rider June 1, 2008, subject to refund. On July 15, 2008, the PPUC directed the ALJ to consolidate the complaints against Met-Ed with its investigation and a litigation schedule was adopted. Hearings and briefing for both Met-Ed and Penelec have concluded and the companies are awaiting a Recommended Decision from the ALJ. The TSCs include a component from under-recovery of actual transmission costs incurred during the prior period (Met-Ed - $144 million and Penelec - $4 million) and future transmission cost projections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec - $92 million). Met-Ed received PPUC approval for a transition approach that would recover past under-recovered costs plus carrying charges through the new TSC over thirty-one months and defer a portion of the projected costs ($92 million) plus carrying charges for recovery through future TSCs by December 31, 2010.
On April 15, 2009, Met-Ed and Penelec filed revised TSCs with the PPUC for the period June 1, 2009 through May 31, 2010, as required in connection with the PPUC’s January 2007 rate order. For Penelec’s customers, the new TSC would result in an approximate 1% decrease in monthly bills, reflecting projected PJM transmission costs as well as a reconciliation for costs already incurred. The TSC for Met-Ed’s customers would increase to recover the additional PJM charges paid by Met-Ed in the previous year and to reflect updated projected costs. In order to gradually transition customers to the higher rate, Met-Ed is proposing to continue to recover the prior period deferrals allowed in the PPUC’s May 2008 Order and defer $57.5 million of projected costs into a future TSC to be fully recovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed’s customers would increase approximately 9.4% for the period June 2009 through May 2010.
On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. The bill addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters and alternative energy. Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009 and a smart meter procurement and installation plan by August 14, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. Similar guidelines related to Smart Meter deployment were issued for comment on March 30, 2009.
Major provisions of the legislation include:
· | power acquired by utilities to serve customers after rate caps expire will be procured through a competitive procurement process that must include a mix of long-term and short-term contracts and spot market purchases; |
· | the competitive procurement process must be approved by the PPUC and may include auctions, RFPs, and/or bilateral agreements; |
· | utilities must provide for the installation of smart meter technology within 15 years; |
· | a minimum reduction in peak demand of 4.5% by May 31, 2013; |
· | minimum reductions in energy consumption of 1% and 3% by May 31, 2011 and May 31, 2013, respectively; and |
· | an expanded definition of alternative energy to include additional types of hydroelectric and biomass facilities. |
Legislation addressing rate mitigation and the expiration of rate caps was not enacted in 2008; however, several bills addressing these issues have been introduced in the current legislative session, which began in January 2009. The final form and impact of such legislation is uncertain.
On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.
On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The companies’ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act 129. The plan proposes a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. Met-Ed and Penelec have requested PPUC approval of their plan by November 2009.
On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance Filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $51 million), overall rates would remain unchanged. The PPUC must act on this filing within 120 days.
(D) NEW JERSEY
JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of March 31, 2009, the accumulated deferred cost balance totaled approximately $165 million.
In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June 7, 2004, supporting continuation of the current level and duration of the funding of TMI-2 decommissioning costs by New Jersey customers without a reduction, termination or capping of the funding. On September 30, 2004, JCP&L filed an updated TMI-2 decommissioning study. This study resulted in an updated total decommissioning cost estimate of $729 million (in 2003 dollars) compared to the estimated $528 million (in 2003 dollars) from the prior 1995 decommissioning study. The DPA filed comments on February 28, 2005 requesting that decommissioning funding be suspended. On March 18, 2005, JCP&L filed a response to those comments. JCP&L responded to additional NJBPU staff discovery requests in May and November 2007 and also submitted comments in the proceeding in November 2007. A schedule for further NJBPU proceedings has not yet been set. On March 13, 2009, JCP&L filed its annual SBC Petition with the NJBPU that includes a request for a reduction in the level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009. This matter is currently pending before the NJBPU.
On August 1, 2005, the NJBPU established a proceeding to determine whether additional ratepayer protections are required at the state level in light of the repeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulations effective October 2, 2006 that prevent a holding company that owns a gas or electric public utility from investing more than 25% of the combined assets of its utility and utility-related subsidiaries into businesses unrelated to the utility industry. These regulations are not expected to materially impact FirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued an additional draft proposal on March 31, 2006 addressing various issues including access to books and records, ring-fencing, cross subsidization, corporate governance and related matters. Following public hearing and consideration of comments from interested parties, the NJBPU approved final regulations effective April 6, 2009. These regulations are not expected to materially impact FirstEnergy or JCP&L.
New Jersey statutes require that the state periodically undertake a planning process, known as the EMP, to address energy related issues including energy security, economic growth, and environmental impact. The EMP is to be developed with involvement of the Governor’s Office and the Governor’s Office of Economic Growth, and is to be prepared by a Master Plan Committee, which is chaired by the NJBPU President and includes representatives of several State departments.
The EMP was issued on October 22, 2008, establishing five major goals:
· | maximize energy efficiency to achieve a 20% reduction in energy consumption by 2020; |
· | reduce peak demand for electricity by 5,700 MW by 2020; |
· | meet 30% of the state’s electricity needs with renewable energy by 2020; |
· | examine smart grid technology and develop additional cogeneration and other generation resources consistent with the state’s greenhouse gas targets; and |
· | invest in innovative clean energy technologies and businesses to stimulate the industry’s growth in New Jersey. |
On January 28, 2009, the NJBPU adopted an order establishing the general process and contents of specific EMP plans that must be filed by December 31, 2009 by New Jersey electric and gas utilities in order to achieve the goals of the EMP. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on its operations or those of JCP&L.
In support of the New Jersey Governor’s Economic Assistance and Recovery Plan, JCP&L announced its intent to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. An estimated $40 million will be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. Approximately $34 million will be spent implementing new demand response programs as well as expanding on existing programs. Another $11 million will be spent on energy efficiency, specifically replacing transformers and capacitor control systems and installing new LED street lights. The remaining $13 million will be spent on energy efficiency programs that will complement those currently being offered. Completion of the projects is dependent upon resolution of regulatory issues including recovery of the costs associated with plan implementation.
(E) FERC MATTERS
Transmission Service between MISO and PJM
On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is subject to review and approval by the FERC. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements.
PJM Transmission Rate
On January 31, 2005, certain PJM transmission owners made filings with the FERC pursuant to a settlement agreement previously approved by the FERC. JCP&L, Met-Ed and Penelec were parties to that proceeding and joined in two of the filings. In the first filing, the settling transmission owners submitted a filing justifying continuation of their existing rate design within the PJM RTO. Hearings were held and numerous parties appeared and litigated various issues concerning PJM rate design; notably AEP, which proposed to create a "postage stamp", or average rate for all high voltage transmission facilities across PJM and a zonal transmission rate for facilities below 345 kV. This proposal would have the effect of shifting recovery of the costs of high voltage transmission lines to other transmission zones, including those where JCP&L, Met-Ed, and Penelec serve load. On April 19, 2007, the FERC issued an order finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.
On May 18, 2007, certain parties filed for rehearing of the FERC’s April 19, 2007 order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral argument was held on April 13, 2009, and a decision is expected this summer.
The FERC’s orders on PJM rate design will prevent the allocation of a portion of the revenue requirement of existing transmission facilities of other utilities to JCP&L, Met-Ed and Penelec. In addition, the FERC’s decision to allocate the cost of new 500 kV and above transmission facilities on a PJM-wide basis will reduce the costs of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.
Post Transition Period Rate Design
The FERC had directed MISO, PJM, and the respective transmission owners to make filings on or before August 1, 2007 to reevaluate transmission rate design within MISO, and between MISO and PJM. On August 1, 2007, filings were made by MISO, PJM, and the vast majority of transmission owners, including FirstEnergy affiliates, which proposed to retain the existing transmission rate design. These filings were approved by the FERC on January 31, 2008. As a result of the FERC’s approval, the rates charged to FirstEnergy’s load-serving affiliates for transmission service over existing transmission facilities in MISO and PJM are unchanged. In a related filing, MISO and MISO transmission owners requested that the current MISO pricing for new transmission facilities that spreads 20% of the cost of new 345 kV and higher transmission facilities across the entire MISO footprint (known as the RECB methodology) be retained.
On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009.
Duquesne’s Request to Withdraw from PJM
On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with the FERC to exit PJM and to join MISO. Duquesne’s proposed move would affect numerous FirstEnergy interests, including but not limited to the terms under which FirstEnergy’s Beaver Valley Plant would continue to participate in PJM’s energy markets. FirstEnergy, therefore, intervened and participated fully in all of the FERC dockets that were related to Duquesne’s proposed move.
In November, 2008, Duquesne and other parties, including FirstEnergy, negotiated a settlement that would, among other things, allow for Duquesne to remain in PJM and provide for a methodology for Duquesne to meet the PJM capacity obligations for the 2011-2012 auction that excluded the Duquesne load. The settlement agreement was filed on December 10, 2008 and approved by the FERC in an order issued on January 29, 2009. MISO opposed the settlement agreement pending resolution of exit fees alleged to be owed by Duquesne. The FERC did not resolve the exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearing of the FERC's January 29, 2009 order approving the settlement. Thereafter, FirstEnergy and other parties filed in opposition to the rehearing request. The PPUC's rehearing request, and the pleadings in opposition thereto, are pending before the FERC.
Changes ordered for PJM Reliability Pricing Model (RPM) Auction
On May 30, 2008, a group of PJM load-serving entities, state commissions, consumer advocates, and trade associations (referred to collectively as the RPM Buyers) filed a complaint at the FERC against PJM alleging that three of the four transitional RPM auctions yielded prices that are unjust and unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. However, the FERC did grant the RPM Buyers’ request for a technical conference to review aspects of the RPM. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement talks. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.
On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM; however, the basic construct of RPM remains intact. On April 3, 2009, PJM filed with the FERC requesting clarification on certain aspects of the March 26, 2009 Order. On April 27, 2009, PJM submitted a compliance filing addressing the changes the FERC ordered in the March 26, 2009 Order; numerous parties have filed requests for rehearing of the March 26, 2009 Order. In addition, the FERC has indefinitely postponed the technical conference on RPM granted in the FERC order of September 19, 2008.
MISO Resource Adequacy Proposal
MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn Power, and FES. This requirement is proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.
On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process is expected to start as planned effective June 1, 2009, the beginning of the MISO planning year.
FES Sales to Affiliates
On October 24, 2008, FES, on its own behalf and on behalf of its generation-controlling subsidiaries, filed an application with the FERC seeking a waiver of the affiliate sales restrictions between FES and the Ohio Companies. The purpose of the waiver is to ensure that FES will be able to continue supplying a material portion of the electric load requirements of the Ohio Companies after January 1, 2009 pursuant to either an ESP or MRO as filed with the PUCO. FES previously obtained a similar waiver for electricity sales to its affiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, the FERC issued an order granting the waiver request and the Ohio Companies made the required compliance filing on December 30, 2008. In January 2009, several parties filed for rehearing of the FERC’s December 23, 2008 order. In response, FES filed an answer to requests for rehearing on February 5, 2009. The requests and responses are pending before the FERC.
FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of the December 23, 2008 waiver.
On October 31, 2008, FES executed a Third Restated Partial Requirements Agreement with Met-Ed, Penelec, and Waverly effective November 1, 2008. The Third Restated Partial Requirements Agreement limits the amount of capacity and energy required to be supplied by FES in 2009 and 2010 to roughly two-thirds of these affiliates’ power supply requirements. Met-Ed, Penelec, and Waverly have committed resources in place for the balance of their expected power supply during 2009 and 2010. Under the Third Restated Partial Requirements Agreement, Met-Ed, Penelec, and Waverly are responsible for obtaining additional power supply requirements created by the default or failure of supply of their committed resources. Prices for the power provided by FES were not changed in the Third Restated Partial Requirements Agreement.
10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS
FSP FAS 157-4 – “Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly”
In April 2009, the FASB issued Staff Position FAS 157-4, which provides additional guidance to consider in estimating fair value when there has been a significant decrease in market activity for a financial asset. The FSP establishes a two-step process requiring a reporting entity to first determine if a market is not active in relation to normal market activity for the asset. If evidence indicates the market is not active, an entity would then need to determine whether a quoted price in the market is associated with a distressed transaction. An entity will need to further analyze the transactions or quoted prices, and an adjustment to the transactions or quoted prices may be necessary to estimate fair value. Additional disclosures related to the inputs and valuation techniques used in the fair value measurements are also required. The FSP is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009. While the FSP will expand disclosure requirements, FirstEnergy does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 115-2 and FAS 124-2 - “Recognition and Presentation of Other-Than-Temporary Impairments” |
In April 2009, the FASB issued Staff Position FAS 115-2 and FAS 124-2, which changes the method to determine whether an other-than-temporary impairment exists for debt securities and the amount of impairment to be recorded in earnings. Under the FSP, management will be required to assert it does not have the intent to sell the debt security, and it is more likely than not it will not have to sell the debt security before recovery of its cost basis. If management is unable to make these assertions, the debt security will be deemed other-than-temporarily impaired and the security will be written down to fair value with the full charge recorded through earnings. If management is able to make the assertions, but there are credit losses associated with the debt security, the portion of impairment related to credit losses will be recognized in earnings while the remaining impairment will be recognized through other comprehensive income. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009 and does not expect the FSP to have a material effect upon its financial statements.
| FSP FAS 107-1 and APB 28-1 - “Interim Disclosures about Fair Value of Financial Instruments” |
In April 2009, the FASB issued Staff Position FAS 107-1 and APB 28-1, which requires disclosures of the fair value of financial instruments in interim financial statements, as well as in annual financial statements. The FSP also requires entities to disclose the methods and significant assumptions used to estimate the fair value of financial instruments in both interim and annual financial statements. The FSP is effective for interim and annual reporting periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. FirstEnergy will adopt the FSP for its interim period ending June 30, 2009, and expects to expand its disclosures regarding the fair value of financial instruments.
FSP FAS 132 (R)-1 – “Employers’ Disclosures about Postretirement Benefit Plan Assets”
In December 2008, the FASB issued Staff Position FAS 132(R)-1, which provides guidancea standard on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plan. Requirements of this FSP include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This FSPstandard is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assetsassets.
In June 2009, the FASB amended the derecognition guidance in the Transfers and Servicing Topic of the FASB Accounting Standards Codification and eliminates the concept of a QSPE. It requires an evaluation of all existing QSPEs to determine whether they must be consolidated. This standard is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.
In June 2009, the FASB amended the consolidation guidance applied to VIEs. This standard replaces the quantitative approach previously required to determine which entity has a controlling financial interest in a VIE with a qualitative approach. Under the new approach, the primary beneficiary of a VIE is the entity that has both (a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance, and (b) the obligation to absorb losses of the entity, or the right to receive benefits from the entity, that could be significant to the VIE. This standard also requires ongoing reassessments of whether an entity is the primary beneficiary of a VIE and enhanced disclosures about an entity’s involvement in VIEs. The standard is effective for fiscal years beginning after November 15, 2009. FirstEnergy is currently evaluating the impact of adopting this standard on its financial statements.
In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance to determine fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for fiscal years beginning October 1, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.
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, and through its subsidiaries, FGCO and NGC, owns or leases and operates and maintains FirstEnergy's fossil and hydroelectric generation facilities and owns FirstEnergy's nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.
FES' revenues have been primarily derived from the sale of electricity (provided from FES' generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010. FES also supplied, through May 31, 2009, a portion of Penn's default service requirements at market-based rates as a result of this FSP.Penn's 2008 competitive solicitations. FES' revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.
The demand for electricity produced and sold by FES, along with the price of that electricity, is impacted by conditions in competitive power markets, global economic activity, economic activity in the Midwest and Mid-Atlantic regions, and weather conditions in FirstEnergy’s service territories. The current recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, have adversely affected FES’ operations and revenues.
The level of demand for electricity directly impacts FES’ generation revenues, the quantity of electricity produced, purchased power expense and fuel expense. FirstEnergy and FES have taken various actions and instituted a number of changes in operating practices to mitigate these external influences. These actions include employee severances, wage reductions, employee and retiree benefit changes, reduced levels of overtime and the use of fewer contractors. The continuation of recessionary economic conditions, coupled with unusually mild weather patterns and the resulting impact on electricity prices and demand, could impact FES’ future operating performance and financial condition and may require further changes in FES’ operations.
For additional information with respect to FES, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.
Results of Operations
In the first nine months of 2009, net income increased to $668 million from $344 million in the same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale of 9% of its participation in OVEC ($158 million after-tax), an increase in investment income of $142 million resulting primarily from the sale of securities held in the nuclear decommissioning trusts and an increase in gross sales margins.
Revenues
Revenues increased by $260 million in the first nine months of 2009 compared to the same period in 2008 primarily due to the OVEC sale and increase in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:
11. SEGMENT INFORMATION
FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as “reportable operating segments.” | | Nine Months Ended | | | | | | September 30 | | Increase | | Revenues by Type of Service | | 2009 | | 2008 | | (Decrease) | | | | (In millions) | | Non-Affiliated Generation Sales: | | | | | | | | | | | | | | | | | | ) | | | | | | | | | | | | Total Non-Affiliated Generation Sales | | | | | | | | | | ) | Affiliated Generation Sales | | | | | | | | | | | | | | | | | | | | | | Sale of OVEC participation interest | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The energy delivery services segment designs, constructs, operates and maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations of FirstEnergy’s Pennsylvania and New Jersey electric utility subsidiaries. Itslower retail revenues are primarily derivedresulted from the deliveryexpiration of electricity, cost recoverygovernment aggregation programs in Ohio at the end of regulatory assets,2008 that were supplied by FES, partially offset by increased revenue in both the PJM and default service electricMISO markets. The increase in MISO retail sales is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales to non-shopping customersvolumes and favorable settlements on hedged transactions in its Pennsylvania and New Jersey franchise areas. Its results reflect the commodity costs of securing electric generation from FES under partial requirements purchased power agreements and from non-affiliated power suppliers as well as the net PJM transmission expenses related to the delivery of that generation load.MISO, offset by decreased sales volumes in PJM.
The competitive energy services segment supplies electric power to its electric utility affiliates, provides competitive electricity sales primarily in Ohio, Pennsylvania, Maryland and Michigan, owns or leases and operates FirstEnergy’s generating facilities and purchases electricity to meet its sales obligations. The segment's net income is primarily derived from theincreased affiliated company PSA sales and the non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISOwere due to deliver electricityhigher unit prices to the segment’s customers.Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The segment’s internal revenues representhigher unit prices reflected the affiliated company PSA sales.
The Ohio transitional generation services segment represents the regulated generation commodity operations of FirstEnergy’s Ohio electric utility subsidiaries. Its revenues are primarily derived from electric generation sales to non-shopping customers under the PLR obligationsresults of the Ohio Companies. Its results reflectCompanies' power procurement processes in the purchasefirst half of electricity from third parties and the competitive energy services segment through a CBP, the deferral and amortization of certain fuel costs authorized for recovery by the energy delivery services segment and the net MISO transmission revenues and expenses related2009 (see Regulatory Matters – Ohio). The higher sales to the deliveryPennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.
In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs beginning in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and as of September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation load. This segment’s total assets consist of accounts receivable for generationrequirements.
The following tables summarize the price and volume factors contributing to changes in revenues from retail customers.non-affiliated and affiliated generation sales in the first nine months of 2009 compared to the same period last year:
| | Increase | | Source of Change in Non-Affiliated Generation Revenues | | | | | | (In millions) | | Retail: | | | | | Effect of 34.3% decrease in sales volumes | | $ | (166 | ) | Change in prices | | | | | | | | | ) | Wholesale: | | | | | Effect of 3.5% decrease in sales volumes | | | (18 | ) | Change in prices | | | | | | | | | | Net Decrease in Non-Affiliated Generation Revenues | | | | ) |
| | Increase | | Source of Change in Affiliated Generation Revenues | | | | | | (In millions) | | Ohio Companies: | | | | | Effect of 28.9% decrease in sales volumes | | $ | (508 | ) | Change in prices | | | | | | | | | | Pennsylvania Companies: | | | | | Effect of 11.1% increase in sales volumes | | | 57 | | Change in prices | | | | ) | | | | | | Net Increase in Affiliated Generation Revenues | | | | |
Segment Financial Information | | | | | | | | | | | | | | | | | | | | | | | | | | | Ohio | | | | | | | | | | | | | Energy | | | Competitive | | | Transitional | | | | | | | | | | | | | Delivery | | | Energy | | | Generation | | | | | | Reconciling | | | | | Three Months Ended | | Services | | | Services | | | Services | | | Other | | | Adjustments | | | Consolidated | | | | (In millions) | | March 31, 2009 | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,109 | | | $ | 335 | | | $ | 912 | | | $ | 7 | | | $ | (29 | ) | | $ | 3,334 | | Internal revenues | | | - | | | | 893 | | | | - | | | | - | | | | (893 | ) | | | - | | Total revenues | | | 2,109 | | | | 1,228 | | | | 912 | | | | 7 | | | | (922 | ) | | | 3,334 | | Depreciation and amortization | | | 472 | | | | 64 | | | | (45 | ) | | | 1 | | | | 3 | | | | 495 | | Investment income (loss), net | | | 29 | | | | (29 | ) | | | 1 | | | | - | | | | (12 | ) | | | (11 | ) | Net interest charges | | | 110 | | | | 18 | | | | - | | | | 1 | | | | 37 | | | | 166 | | Income taxes | | | (28 | ) | | | 103 | | | | 16 | | | | (17 | ) | | | (20 | ) | | | 54 | | Net income (loss) | | | (42 | ) | | | 155 | | | | 24 | | | | 17 | | | | (39 | ) | | | 115 | | Total assets | | | 22,669 | | | | 9,925 | | | | 336 | | | | 632 | | | | (5 | ) | | | 33,557 | | Total goodwill | | | 5,550 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,574 | | Property additions | | | 165 | | | | 421 | | | | - | | | | 49 | | | | 19 | | | | 654 | | | | | | | | | | | | | | | | | | | | | | | | | | | March 31, 2008 | | | | | | | | | | | | | | | | | | | | | | | | | External revenues | | $ | 2,212 | | | $ | 329 | | | $ | 707 | | | $ | 40 | | | $ | (11 | ) | | $ | 3,277 | | Internal revenues | | | - | | | | 776 | | | | - | | | | - | | | | (776 | ) | | | - | | Total revenues | | | 2,212 | | | | 1,105 | | | | 707 | | | | 40 | | | | (787 | ) | | | 3,277 | | Depreciation and amortization | | | 255 | | | | 53 | | | | 4 | | | | - | | | | 5 | | | | 317 | | Investment income (loss), net | | | 45 | | | | (6 | ) | | | 1 | | | | - | | | | (23 | ) | | | 17 | | Net interest charges | | | 103 | | | | 27 | | | | - | | | | - | | | | 41 | | | | 171 | | Income taxes | | | 119 | | | | 58 | | | | 15 | | | | 14 | | | | (19 | ) | | | 187 | | Net income | | | 179 | | | | 87 | | | | 23 | | | | 22 | | | | (34 | ) | | | 277 | | Total assets | | | 23,211 | | | | 8,108 | | | | 257 | | | | 281 | | | | 558 | | | | 32,415 | | Total goodwill | | | 5,582 | | | | 24 | | | | - | | | | - | | | | - | | | | 5,606 | | Property additions | | | 255 | | | | 462 | | | | - | | | | 12 | | | | (18 | ) | | | 711 | |
Reconciling adjustments to segment operating results from internal management reporting to consolidated external financial reporting primarily consist of interest expense related to holding company debt, corporate support services revenues and expenses and elimination of intersegment transactions.
Transmission revenues decreased $56 million due primarily to reduced loads in MISO following the expiration of the government aggregation programs in Ohio at the end of 2008. Other revenue increased $46 million primarily due to rental income associated with NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit 2.
12. SUPPLEMENTAL GUARANTOR INFORMATIONExpenses
On July 13, 2007, FGCO completedTotal expenses decreased by $82 million in the first nine months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2009 from the same period last year:
Source of Change in Fuel and Purchased Power | | | | | | | (In millions) | | Fossil Fuel: | | | | | Change due to increased unit costs | | $ | 112 | | Change due to volume consumed | | | (230 | ) | | | | (118 | ) | Nuclear Fuel: | | | | | Change due to increased unit costs | | | 14 | | Change due to volume consumed | | | (7 | ) | | | | 7 | | Non-affiliated Purchased Power: | | | | | Change due to increased unit costs | | | 73 | | Change due to volume purchased | | | (170 | ) | | | | (97 | ) | Affiliated Purchased Power: | | | | | Change due to increased unit costs | | | 71 | | Change due to volume purchased | | | 2 | | | | | 73 | | Net Decrease in Fuel and Purchased Power Costs | | | | ) |
Fossil fuel costs decreased $118 million in the first nine months of 2009 as a saleresult of decreased coal consumption, reflecting lower generation. Higher unit prices, which are expected to continue during the remainder of 2009, were due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs increased slightly due to increased unit prices in the first nine months of 2009 compared to the same period of 2008.
Purchased power costs from non-affiliates decreased primarily as a result of reduced volume requirements, partially offset by higher capacity costs. Purchases from affiliated companies increased as a result of higher unit costs on purchases from OE’s and leaseback transactionTE’s leasehold interests in Beaver Valley Unit 2 and Perry.
Other operating expenses increased by $28 million in the first nine months of 2009 from the same period of 2008. Higher expenses in the 2009 period relate to increased transmission expenses ($64 million) due to increased net congestion charges in PJM and higher transmission loss expenses in MISO and PJM combined with increased other expenses ($14 million) relating to increased intersegment billings for its 93.825% undividedleasehold costs from the Ohio Companies and higher pension expense. These increases were partially offset by lower fossil operating costs ($46 million) and nuclear operating costs ($4 million). Decreased fossil operating costs were primarily due to a reduction in contractor and material costs and more labor dedicated to capital projects compared to the prior year.
Depreciation expense increased by $22 million in the first nine months of 2009 primarily due to NGC’s increased ownership interest in Bruce MansfieldBeaver Valley Unit 1. FES has fully2 and unconditionally and irrevocably guaranteed allPerry.
Other Expense
Total other expense in the first nine months of FGCO’s obligations under each2009 was $156 million lower than the first nine months 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 interest2008, primarily due to a $137 million increase 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 FESearnings from nuclear decommissioning trust investments and a financing for FGCO.decline in interest expense (net of capitalized interest) of $21 million primarily due to the repayment of notes payable to affiliates.
The condensed consolidating statements of income for the three months ended March 31, 2009, and 2008, consolidating balance sheets as of March 31, 2009, and December 31, 2008, and consolidating statements of cash flows for the three months ended March 31, 2009, and 2008 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.
OHIO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.
For additional information with respect to OE, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.
Results of Operations
In the first nine months of 2009, net income decreased to $80 million from $166 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009.
Revenues
Revenues increased by $59 million, or 3.0%, in the first nine months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($204 million) and wholesale revenues ($80 million), partially offset by decreases in distribution throughput revenues ($203 million) and other miscellaneous revenues ($22 million).
Retail generation revenues increased primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflecting a decrease in customer shopping in those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s service territory. Average prices increased primarily due to an increase in OE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under OE’s CBP.
Changes in retail generation sales and revenues in the first nine months of 2009 from the same period in 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Increase (Decrease) | | | | | | Residential | | 6.6 | % | Commercial | | 10.4 | % | Industrial | | (19.0 | )% | Net Decrease in Generation Sales | | (0.6 | )% |
Retail Generation Revenues | | Increase | | | | (In millions) | | Residential | | $ | 93 | | Commercial | | | 87 | | Industrial | | | 24 | | Increase in Generation Revenues | | $ | 204 | |
The increase in wholesale revenues was primarily due to higher average unit prices.
Revenues from distribution throughput decreased by $203 million in the first nine months of 2009 compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers reflect the weakened economy. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 1,201,895 | | | $ | 545,926 | | | $ | 395,628 | | | $ | (917,343 | ) | | $ | 1,226,106 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 2,095 | | | | 274,847 | | | | 29,216 | | | | - | | | | 306,158 | | Purchased power from non-affiliates | | | 160,342 | | | | - | | | | - | | | | - | | | | 160,342 | | Purchased power from affiliates | | | 915,261 | | | | 2,082 | | | | 63,207 | | | | (917,343 | ) | | | 63,207 | | Other operating expenses | | | 38,267 | | | | 104,443 | | | | 152,456 | | | | 12,190 | | | | 307,356 | | Provision for depreciation | | | 1,019 | | | | 30,020 | | | | 31,649 | | | | (1,315 | ) | | | 61,373 | | General taxes | | | 4,706 | | | | 12,626 | | | | 6,044 | | | | - | | | | 23,376 | | Total expenses | | | 1,121,690 | | | | 424,018 | | | | 282,572 | | | | (906,468 | ) | | | 921,812 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME | | | 80,205 | | | | 121,908 | | | | 113,056 | | | | (10,875 | ) | | | 304,294 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | | net income from equity investees | | | 120,513 | | | | (47 | ) | | | (29,637 | ) | | | (117,192 | ) | | | (26,363 | ) | Interest expense to affiliates | | | (34 | ) | | | (1,758 | ) | | | (1,187 | ) | | | - | | | | (2,979 | ) | Interest expense - other | | | (2,520 | ) | | | (21,058 | ) | | | (15,168 | ) | | | 16,219 | | | | (22,527 | ) | Capitalized interest | | | 51 | | | | 7,750 | | | | 2,277 | | | | - | | | | 10,078 | | Total other income (expense) | | | 118,010 | | | | (15,113 | ) | | | (43,715 | ) | | | (100,973 | ) | | | (41,791 | ) | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 198,215 | | | | 106,795 | | | | 69,341 | | | | (111,848 | ) | | | 262,503 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES | | | 27,534 | | | | 39,142 | | | | 22,929 | | | | 2,217 | | | | 91,822 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 170,681 | | | $ | 67,653 | | | $ | 46,412 | | | $ | (114,065 | ) | | $ | 170,681 | |
Changes in distribution KWH deliveries and revenues in the first nine months of 2009 from the same period in 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | | | | | | Residential | | | (3.3 | )% | Commercial | | | (4.8 | )% | Industrial | | | (24.5 | )% | Decrease in Distribution Deliveries | | | (11.1 | )% |
Distribution Revenues | | Decrease | | | | (In millions) | Residential | | $ | (41 | ) | Commercial | | | (75 | ) | Industrial | | | (87 | ) | Decrease in Distribution Revenues | | $ | (203 | ) |
Expenses
Total expenses increased by $171 million in the first nine months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | | | | | (In millions) | | Purchased power costs | | $ | 248 | | Other operating costs | | | (51 | ) | Provision for depreciation | | | 8 | | Amortization of regulatory assets, net | | | (28 | ) | General taxes | | | (6 | ) | Net Increase in Expenses | | $ | 171 | |
Higher purchased power costs reflect the results of OE’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). The decrease in other operating costs for the first nine months of 2009 was primarily due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), partially offset by costs for economic development programs and energy efficiency obligations under OE’s ESP. Higher depreciation expense in the first nine months of 2009 reflected capital additions subsequent to the third quarter of 2008. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization and distribution reliability deferrals in 2008, partially offset by lower MISO transmission cost deferrals. The decrease in general taxes for the first nine months of 2009 was primarily due to lower Ohio KWH taxes.
Other Expenses
Other expenses increased by $15 million in the first nine months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of $300 million of FMBs by OE in October 2008.
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF INCOME | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | REVENUES | | $ | 1,099,848 | | | $ | 567,701 | | | $ | 325,684 | | | $ | (894,117 | ) | | $ | 1,099,116 | | | | | | | | | | | | | | | | | | | | | | | EXPENSES: | | | | | | | | | | | | | | | | | | | | | Fuel | | | 2,138 | | | | 291,239 | | | | 28,312 | | | | - | | | | 321,689 | | Purchased power from non-affiliates | | | 206,724 | | | | - | | | | - | | | | - | | | | 206,724 | | Purchased power from affiliates | | | 891,979 | | | | 2,138 | | | | 25,485 | | | | (894,117 | ) | | | 25,485 | | Other operating expenses | | | 37,596 | | | | 107,167 | | | | 139,595 | | | | 12,188 | | | | 296,546 | | Provision for depreciation | | | 307 | | | | 26,599 | | | | 24,194 | | | | (1,358 | ) | | | 49,742 | | General taxes | | | 5,415 | | | | 11,570 | | | | 6,212 | | | | - | | | | 23,197 | | Total expenses | | | 1,144,159 | | | | 438,713 | | | | 223,798 | | | | (883,287 | ) | | | 923,383 | | | | | | | | | | | | | | | | | | | | | | | OPERATING INCOME (LOSS) | | | (44,311 | ) | | | 128,988 | | | | 101,886 | | | | (10,830 | ) | | | 175,733 | | | | | | | | | | | | | | | | | | | | | | | OTHER INCOME (EXPENSE): | | | | | | | | | | | | | | | | | | | | | Miscellaneous income (expense), including | | | | | | | | | | | | | | | | | | | | | net income from equity investees | | | 121,725 | | | | (1,208 | ) | | | (6,537 | ) | | | (116,884 | ) | | | (2,904 | ) | Interest expense to affiliates | | | (82 | ) | | | (5,289 | ) | | | (1,839 | ) | | | - | | | | (7,210 | ) | Interest expense - other | | | (3,978 | ) | | | (25,968 | ) | | | (11,018 | ) | | | 16,429 | | | | (24,535 | ) | Capitalized interest | | | 21 | | | | 6,228 | | | | 414 | | | | - | | | | 6,663 | | Total other income (expense) | | | 117,686 | | | | (26,237 | ) | | | (18,980 | ) | | | (100,455 | ) | | | (27,986 | ) | | | | | | | | | | | | | | | | | | | | | | INCOME BEFORE INCOME TAXES | | | 73,375 | | | | 102,751 | | | | 82,906 | | | | (111,285 | ) | | | 147,747 | | | | | | | | | | | | | | | | | | | | | | | INCOME TAXES (BENEFIT) | | | (16,609 | ) | | | 39,285 | | | | 32,764 | | | | 2,323 | | | | 57,763 | | | | | | | | | | | | | | | | | | | | | | | NET INCOME | | $ | 89,984 | | | $ | 63,466 | | | $ | 50,142 | | | $ | (113,608 | ) | | $ | 89,984 | |
THE CLEVELAND ELECTRIC ILLUMINATING COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.
For additional information with respect to CEI, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.
Results of Operations
CEI experienced a net loss of $32 million in the first nine months of 2009 compared to net income of $219 million in the same period of 2008. The net loss in 2009 resulted from regulatory charges ($228 million) related to the implementation of CEI's ESP. The 2009 results were also adversely impacted by increased purchased power costs, partially offset by higher deferrals of new regulatory assets and lower other operating costs.
Revenues
Revenues decreased by $35 million, or 2.5%, in the first nine months of 2009 compared to the same period of 2008 primarily due to decreases in distribution revenues ($117 million), transmission revenues ($14 million) and other miscellaneous revenues ($7 million), partially offset by an increase in retail generation revenues ($103 million).
Retail generation revenues increased in the first nine months of 2009 due to higher average unit prices in all customer classes partially offset by decreased sales volume to residential and industrial customers compared to the same period of 2008. Average prices increased due to an increase in CEI’s fuel cost recovery rider that was effective from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under CEI's CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volumes for commercial customers resulted from a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008 following the termination of certain government aggregation programs in CEI’s service territory.
Changes in retail generation sales and revenues in the first nine months of 2009 compared to the same period in 2008 are summarized in the following tables:
| | Increase | | Retail Generation KWH Sales | | (Decrease) | | | | | | | Residential | | | (2.7 | )% | Commercial | | | 4.8 | % | Industrial | | | (14.6 | )% | Decrease in Retail Generation Sales | | | (6.4 | )% |
Retail Generation Revenues | | Increase | | | | (in millions) | | Residential | | $ | 30 | | Commercial | | | 40 | | Industrial | | | 33 | | Increase in Generation Revenues | | $ | 103 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING BALANCE SHEETS | | | | | | | | | | | | | | | | | | As of March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | ASSETS | | | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | | Receivables- | | | | | | | | | | | | | | | | | | | | | Customers | | | 54,554 | | | | - | | | | - | | | | - | | | | 54,554 | | Associated companies | | | 295,513 | | | | 192,816 | | | | 125,514 | | | | (325,908 | ) | | | 287,935 | | Other | | | 2,562 | | | | 14,705 | | | | 49,026 | | | | - | | | | 66,293 | | Notes receivable from associated companies | | | 404,869 | | | | 28,268 | | | | - | | | | - | | | | 433,137 | | Materials and supplies, at average cost | | | 8,610 | | | | 349,038 | | | | 210,039 | | | | - | | | | 567,687 | | Prepayments and other | | | 84,466 | | | | 26,589 | | | | 1,107 | | | | - | | | | 112,162 | | | | | 850,574 | | | | 611,450 | | | | 385,686 | | | | (325,908 | ) | | | 1,521,802 | | | | | | | | | | | | | | | | | | | | | | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | | In service | | | 88,064 | | | | 5,477,939 | | | | 4,736,544 | | | | (389,944 | ) | | | 9,912,603 | | Less - Accumulated provision for depreciation | | | 10,821 | | | | 2,732,040 | | | | 1,755,879 | | | | (171,499 | ) | | | 4,327,241 | | | | | 77,243 | | | | 2,745,899 | | | | 2,980,665 | | | | (218,445 | ) | | | 5,585,362 | | Construction work in progress | | | 4,728 | | | | 1,626,685 | | | | 483,418 | | | | - | | | | 2,114,831 | | | | | 81,971 | | | | 4,372,584 | | | | 3,464,083 | | | | (218,445 | ) | | | 7,700,193 | | | | | | | | | | | | | | | | | | | | | | | INVESTMENTS: | | | | | | | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | - | | | | - | | | | 995,476 | | | | - | | | | 995,476 | | Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | | Investment in associated companies | | | 3,712,870 | | | | - | | | | - | | | | (3,712,870 | ) | | | - | | Other | | | 1,714 | | | | 29,982 | | | | 202 | | | | - | | | | 31,898 | | | | | 3,714,584 | | | | 29,982 | | | | 1,058,578 | | | | (3,712,870 | ) | | | 1,090,274 | | | | | | | | | | | | | | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | Accumulated deferred income tax benefits | | | 18,209 | | | | 458,730 | | | | - | | | | (235,332 | ) | | | 241,607 | | Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | | Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Unamortized sale and leaseback costs | | | - | | | | 32,128 | | | | - | | | | 54,174 | | | | 86,302 | | Other | | | 65,233 | | | | 58,004 | | | | 8,332 | | | | (44,428 | ) | | | 87,141 | | | | | 107,690 | | | | 647,712 | | | | 30,942 | | | | (225,586 | ) | | | 560,758 | | | | $ | 4,754,819 | | | $ | 5,661,728 | | | $ | 4,939,289 | | | $ | (4,482,809 | ) | | $ | 10,873,027 | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Currently payable long-term debt | | $ | 708 | | | $ | 930,763 | | | $ | 777,218 | | | $ | (17,747 | ) | | $ | 1,690,942 | | Short-term borrowings- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | - | | | | 345,664 | | | | 440,452 | | | | - | | | | 786,116 | | Other | | | 1,100,000 | | | | - | | | | - | | | | - | | | | 1,100,000 | | Accounts payable- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 361,848 | | | | 132,694 | | | | 232,204 | | | | (317,586 | ) | | | 409,160 | | Other | | | 27,081 | | | | 117,756 | | | | - | | | | - | | | | 144,837 | | Accrued taxes | | | 22,861 | | | | 75,462 | | | | 45,300 | | | | (20,889 | ) | | | 122,734 | | Other | | | 58,938 | | | | 112,048 | | | | 23,023 | | | | 45,975 | | | | 239,984 | | | | | 1,571,436 | | | | 1,714,387 | | | | 1,518,197 | | | | (310,247 | ) | | | 4,493,773 | | | | | | | | | | | | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | | Common stockholder's equity | | | 3,120,406 | | | | 1,901,085 | | | | 1,797,764 | | | | (3,698,849 | ) | | | 3,120,406 | | Long-term debt and other long-term obligations | | | 21,819 | | | | 1,466,373 | | | | 469,839 | | | | (1,287,970 | ) | | | 670,061 | | | | | 3,142,225 | | | | 3,367,458 | | | | 2,267,603 | | | | (4,986,819 | ) | | | 3,790,467 | | | | | | | | | | | | | | | | | | | | | | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,018,156 | | | | 1,018,156 | | Accumulated deferred income taxes | | | - | | | | - | | | | 203,899 | | | | (203,899 | ) | | | - | | Accumulated deferred investment tax credits | | | - | | | | 38,669 | | | | 22,976 | | | | - | | | | 61,645 | | Asset retirement obligations | | | - | | | | 24,274 | | | | 852,799 | | | | - | | | | 877,073 | | Retirement benefits | | | 23,242 | | | | 175,561 | | | | - | | | | - | | | | 198,803 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Lease market valuation liability | | | - | | | | 296,376 | | | | - | | | | - | | | | 296,376 | | Other | | | 17,916 | | | | 17,509 | | | | 51,205 | | | | - | | | | 86,630 | | | | | 41,158 | | | | 579,883 | | | | 1,153,489 | | | | 814,257 | | | | 2,588,787 | | | | $ | 4,754,819 | | | $ | 5,661,728 | | | $ | 4,939,289 | | | $ | (4,482,809 | ) | | $ | 10,873,027 | |
Revenues from distribution throughput decreased by $117 million in the first nine months of 2009 compared to the same period of 2008 due to a decrease in KWH deliveries in all customer classes and lower average unit prices in the residential and commercial sectors. The lower average unit price was the net result of reduced transition rates (see Regulatory Matters – Ohio), partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. The lower KWH deliveries in the first nine months of 2009 were due to weaker economic conditions and a decrease of 14% in cooling degree days in the first nine months of 2009 as compared to the previous year.
Changes in distribution KWH deliveries and revenues in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | | | | | | Residential | | | (4.0 | )% | Commercial | | | (4.7 | )% | Industrial | | | (18.6 | )% | Decrease in Distribution Deliveries | | | (10.8 | )% |
| | | | Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (52 | ) | Commercial | | | (26 | ) | Industrial | | | (39 | ) | Decrease in Distribution Revenues | | $ | (117 | ) |
Expenses
Total operating expenses increased by $343 million in the first nine months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | | | | (in millions) | | Purchased power costs | | $ | 254 | | Other operating costs | | | (52 | ) | Amortization of regulatory assets | | | 200 | | Deferral of new regulatory assets | | | (63 | ) | General Taxes | | | 4 | | Net Increase in Expenses | | $ | 343 | |
Higher purchased power costs reflect the results of CEI’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). Increased amortization of regulatory assets was due to the impairment of CEI’s Extended RTC balance ($216 million) in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. Other operating costs were $52 million lower than in the previous year due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs. The increase in general taxes was primarily due to higher property taxes.
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING BALANCE SHEETS | | | | | | | | | | | | | | | | | | As of December 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | ASSETS | | | | | | | | | | | | | | | | CURRENT ASSETS: | | | | | | | | | | | | | | | | Cash and cash equivalents | | $ | - | | | $ | 39 | | | $ | - | | | $ | - | | | $ | 39 | | Receivables- | | | | | | | | | | | | | | | | | | | | | Customers | | | 86,123 | | | | - | | | | - | | | | - | | | | 86,123 | | Associated companies | | | 363,226 | | | | 225,622 | | | | 113,067 | | | | (323,815 | ) | | | 378,100 | | Other | | | 991 | | | | 11,379 | | | | 12,256 | | | | - | | | | 24,626 | | Notes receivable from associated companies | | | 107,229 | | | | 21,946 | | | | - | | | | - | | | | 129,175 | | Materials and supplies, at average cost | | | 5,750 | | | | 303,474 | | | | 212,537 | | | | - | | | | 521,761 | | Prepayments and other | | | 76,773 | | | | 35,102 | | | | 660 | | | | - | | | | 112,535 | | | | | 640,092 | | | | 597,562 | | | | 338,520 | | | | (323,815 | ) | | | 1,252,359 | | | | | | | | | | | | | | | | | | | | | | | PROPERTY, PLANT AND EQUIPMENT: | | | | | | | | | | | | | | | | | | | | | In service | | | 134,905 | | | | 5,420,789 | | | | 4,705,735 | | | | (389,525 | ) | | | 9,871,904 | | Less - Accumulated provision for depreciation | | | 13,090 | | | | 2,702,110 | | | | 1,709,286 | | | | (169,765 | ) | | | 4,254,721 | | | | | 121,815 | | | | 2,718,679 | | | | 2,996,449 | | | | (219,760 | ) | | | 5,617,183 | | Construction work in progress | | | 4,470 | | | | 1,441,403 | | | | 301,562 | | | | - | | | | 1,747,435 | | | | | 126,285 | | | | 4,160,082 | | | | 3,298,011 | | | | (219,760 | ) | | | 7,364,618 | | | | | | | | | | | | | | | | | | | | | | | INVESTMENTS: | | | | | | | | | | | | | | | | | | | | | Nuclear plant decommissioning trusts | | | - | | | | - | | | | 1,033,717 | | | | - | | | | 1,033,717 | | Long-term notes receivable from associated companies | | | - | | | | - | | | | 62,900 | | | | - | | | | 62,900 | | Investment in associated companies | | | 3,596,152 | | | | - | | | | - | | | | (3,596,152 | ) | | | - | | Other | | | 1,913 | | | | 59,476 | | | | 202 | | | | - | | | | 61,591 | | | | | 3,598,065 | | | | 59,476 | | | | 1,096,819 | | | | (3,596,152 | ) | | | 1,158,208 | | | | | | | | | | | | | | | | | | | | | | | DEFERRED CHARGES AND OTHER ASSETS: | | | | | | | | | | | | | | | | | | | | | Accumulated deferred income tax benefits | | | 24,703 | | | | 476,611 | | | | - | | | | (233,552 | ) | | | 267,762 | | Lease assignment receivable from associated companies | | | - | | | | 71,356 | | | | - | | | | - | | | | 71,356 | | Goodwill | | | 24,248 | | | | - | | | | - | | | | - | | | | 24,248 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Unamortized sale and leaseback costs | | | - | | | | 20,286 | | | | - | | | | 49,646 | | | | 69,932 | | Other | | | 59,642 | | | | 59,674 | | | | 21,743 | | | | (44,625 | ) | | | 96,434 | | | | | 108,593 | | | | 655,421 | | | | 44,353 | | | | (228,531 | ) | | | 579,836 | | | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | | | | | | | | | | | | | | | | | | | | | | | LIABILITIES AND CAPITALIZATION | | | | | | | | | | | | | | | | | | | | | CURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Currently payable long-term debt | | $ | 5,377 | | | $ | 925,234 | | | $ | 1,111,183 | | | $ | (16,896 | ) | | $ | 2,024,898 | | Short-term borrowings- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 1,119 | | | | 257,357 | | | | 6,347 | | | | - | | | | 264,823 | | Other | | | 1,000,000 | | | | - | | | | - | | | | - | | | | 1,000,000 | | Accounts payable- | | | | | | | | | | | | | | | | | | | | | Associated companies | | | 314,887 | | | | 221,266 | | | | 250,318 | | | | (314,133 | ) | | | 472,338 | | Other | | | 35,367 | | | | 119,226 | | | | - | | | | - | | | | 154,593 | | Accrued taxes | | | 8,272 | | | | 60,385 | | | | 30,790 | | | | (19,681 | ) | | | 79,766 | | Other | | | 61,034 | | | | 136,867 | | | | 13,685 | | | | 36,853 | | | | 248,439 | | | | | 1,426,056 | | | | 1,720,335 | | | | 1,412,323 | | | | (313,857 | ) | | | 4,244,857 | | | | | | | | | | | | | | | | | | | | | | | CAPITALIZATION: | | | | | | | | | | | | | | | | | | | | | Common stockholder's equity | | | 2,944,423 | | | | 1,832,678 | | | | 1,752,580 | | | | (3,585,258 | ) | | | 2,944,423 | | Long-term debt and other long-term obligations | | | 61,508 | | | | 1,328,921 | | | | 469,839 | | | | (1,288,820 | ) | | | 571,448 | | | | | 3,005,931 | | | | 3,161,599 | | | | 2,222,419 | | | | (4,874,078 | ) | | | 3,515,871 | | | | | | | | | | | | | | | | | | | | | | | NONCURRENT LIABILITIES: | | | | | | | | | | | | | | | | | | | | | Deferred gain on sale and leaseback transaction | | | - | | | | - | | | | - | | | | 1,026,584 | | | | 1,026,584 | | Accumulated deferred income taxes | | | - | | | | - | | | | 206,907 | | | | (206,907 | ) | | | - | | Accumulated deferred investment tax credits | | | - | | | | 39,439 | | | | 23,289 | | | | - | | | | 62,728 | | Asset retirement obligations | | | - | | | | 24,134 | | | | 838,951 | | | | - | | | | 863,085 | | Retirement benefits | | | 22,558 | | | | 171,619 | | | | - | | | | - | | | | 194,177 | | Property taxes | | | - | | | | 27,494 | | | | 22,610 | | | | - | | | | 50,104 | | Lease market valuation liability | | | - | | | | 307,705 | | | | - | | | | - | | | | 307,705 | | Other | | | 18,490 | | | | 20,216 | | | | 51,204 | | | | - | | | | 89,910 | | | | | 41,048 | | | | 590,607 | | | | 1,142,961 | | | | 819,677 | | | | 2,594,293 | | | | $ | 4,473,035 | | | $ | 5,472,541 | | | $ | 4,777,703 | | | $ | (4,368,258 | ) | | $ | 10,355,021 | |
THE TOLEDO EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.
For additional information with respect to TE, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements and Outlook.
Results of Operations
Net income in the first nine months of 2009 decreased to $14 million from $70 million in the same period of 2008. The change resulted primarily from increased purchased power expense and the completion of transition cost recovery in 2008.
Revenues
Revenues increased slightly in the first nine months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($143 million) and other miscellaneous revenue ($3 million), partially offset by lower distribution revenues ($130 million) and wholesale generation revenues ($16 million).
Retail generation revenues increased in the first nine months of 2009 due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, compared to the same period of 2008. Average prices increased primarily due to an increase in TE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under TE’s CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volume for residential and commercial customers resulted from a decrease in customer shopping. Most of TE’s customers returned to PLR service in December 2008, following the termination of certain government aggregation programs in TE’s service territory.
Changes in retail electric generation KWH sales and revenues in the first nine months of 2009 from the same period of 2008 are summarized in the following tables.
| | Increase | | Retail Generation KWH Sales | | (Decrease) | | | | | | | Residential | | | 2.4 | % | Commercial | | | 30.0 | % | Industrial | | | (17.8 | )% | Net decrease in Retail Generation Sales | | | (2.7 | )% |
Retail Generation Revenues | | Increase | | | | (In millions) | | Residential | | $ | 35 | | Commercial | | | 66 | | Industrial | | | 42 | | Increase in Retail Generation Revenues | | $ | 143 | |
The decrease in wholesale revenues was primarily due to the expiration of a sales agreement with AMP-Ohio at the end of 2008 ($10 million) and lower revenues from associated sales to NGC ($6 million) from TE's leasehold interest in Beaver Valley Unit 2.
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended March 31, 2009 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | NET CASH PROVIDED FROM OPERATING ACTIVITIES | | $ | 200,420 | | | $ | 28,545 | | | $ | 118,902 | | | $ | - | | | $ | 347,867 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | - | | | | 100,000 | | | | - | | | | - | | | | 100,000 | | Short-term borrowings, net | | | 98,881 | | | | 88,308 | | | | 434,105 | | | | - | | | | 621,294 | | Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | (1,189 | ) | | | (626 | ) | | | (334,101 | ) | | | - | | | | (335,916 | ) | Net cash provided from financing activities | | | 97,692 | | | | 187,682 | | | | 100,004 | | | | - | | | | 385,378 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | Property additions | | | (358 | ) | | | (198,631 | ) | | | (213,816 | ) | | | - | | | | (412,805 | ) | Proceeds from asset sales | | | - | | | | 7,573 | | | | - | | | | - | | | | 7,573 | | Sales of investment securities held in trusts | | | - | | | | - | | | | 351,414 | | | | - | | | | 351,414 | | Purchases of investment securities held in trusts | | | - | | | | - | | | | (356,904 | ) | | | - | | | | (356,904 | ) | Loans to associated companies, net | | | (297,641 | ) | | | (6,322 | ) | | | - | | | | - | | | | (303,963 | ) | Other | | | (113 | ) | | | (18,852 | ) | | | 400 | | | | - | | | | (18,565 | ) | Net cash used for investing activities | | | (298,112 | ) | | | (216,232 | ) | | | (218,906 | ) | | | - | | | | (733,250 | ) | | | | | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | | (5 | ) | | | - | | | | - | | | | (5 | ) | Cash and cash equivalents at beginning of period | | | - | | | | 39 | | | | - | | | | - | | | | 39 | | Cash and cash equivalents at end of period | | $ | - | | | $ | 34 | | | $ | - | | | $ | - | | | $ | 34 | |
FIRSTENERGY SOLUTIONS CORP. | | | | | | | | | | | | | | | | | | CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS | | (Unaudited) | | | | | | | | | | | | | | | | | | For the Three Months Ended March 31, 2008 | | FES | | | FGCO | | | NGC | | | Eliminations | | | Consolidated | | | | (In thousands) | | | | | | | | | | | | | | | | | | NET CASH PROVIDED FROM (USED FOR) | | | | | | | | | | | | | | | | OPERATING ACTIVITIES | | $ | 273,827 | | | $ | (122,171 | ) | | $ | 8,108 | | | $ | 188 | | | $ | 159,952 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM FINANCING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | New Financing- | | | | | | | | | | | | | | | | | | | | | Short-term borrowings, net | | | 400,000 | | | | 646,975 | | | | 234,921 | | | | - | | | | 1,281,896 | | Redemptions and Repayments- | | | | | | | | | | | | | | | | | | | | | Long-term debt | | | - | | | | (135,063 | ) | | | (153,540 | ) | | | - | | | | (288,603 | ) | Common stock dividend payments | | | (10,000 | ) | | | - | | | | - | | | | - | | | | (10,000 | ) | Net cash provided from financing activities | | | 390,000 | | | | 511,912 | | | | 81,381 | | | | - | | | | 983,293 | | | | | | | | | | | | | | | | | | | | | | | CASH FLOWS FROM INVESTING ACTIVITIES: | | | | | | | | | | | | | | | | | | | | | Property additions | | | (19,406 | ) | | | (375,391 | ) | | | (81,545 | ) | | | (187 | ) | | | (476,529 | ) | Proceeds from asset sales | | | - | | | | 5,088 | | | | - | | | | - | | | | 5,088 | | Sales of investment securities held in trusts | | | - | | | | - | | | | 173,123 | | | | - | | | | 173,123 | | Purchases of investment securities held in trusts | | | - | | | | - | | | | (181,079 | ) | | | - | | | | (181,079 | ) | Loans to associated companies, net | | | (644,604 | ) | | | - | | | | - | | | | - | | | | (644,604 | ) | Other | | | 183 | | | | (19,438 | ) | | | 12 | | | | (1 | ) | | | (19,244 | ) | Net cash used for investing activities | | | (663,827 | ) | | | (389,741 | ) | | | (89,489 | ) | | | (188 | ) | | | (1,143,245 | ) | | | | | | | | | | | | | | | | | | | | | | Net change in cash and cash equivalents | | | - | | | | - | | | | - | | | | - | | | | - | | Cash and cash equivalents at beginning of period | | | 2 | | | | - | | | | - | | | | - | | | | 2 | | Cash and cash equivalents at end of period | | $ | 2 | | | $ | - | | | $ | - | | | $ | - | | | $ | 2 | |
Revenues from distribution throughput decreased by $130 million in the first nine months of 2009 compared to the same period of 2008 due to lower average unit prices and lower KWH deliveries for all customer classes due primarily to economic conditions. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).
Decreases in distribution KWH deliveries and revenues in the first nine months of 2009 from the same period of 2008 are summarized in the following tables.
Distribution KWH Deliveries | | Decrease | | | | | | | Residential | | | (5.2 | )% | Commercial | | | (10.2 | )% | Industrial | | | (12.9 | )% | Decrease in Distribution Deliveries | | | (10.3 | )% |
Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (31 | ) | Commercial | | | (61 | ) | Industrial | | | (38 | ) | Decrease in Distribution Revenues | | $ | (130 | ) |
Expenses
Total expenses increased $80 million in the first nine months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.
Expenses – Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | | | | | | | | Provision for depreciation | | | | | Amortization of regulatory assets, net | | | | | | | | | |
Higher purchased power costs reflect the results of TE’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). Other operating costs decreased primarily due to reduced transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2 (absence of a refueling outage in the 2009 period). These reductions were partially offset by costs associated with regulatory obligations for economic development and energy efficiency programs under TE’s ESP. The decrease in net amortization of regulatory assets is primarily due to the completion of transition cost recovery and distribution reliability deferrals in 2008, partially offset by lower MISO transmission cost deferrals in 2009.
.
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 provides generation services to franchise customers electing to retain JCP&L as their power supplier. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.
For additional information with respect to JCP&L, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.
Results of Operations
Net income for the first nine months of 2009 decreased to $128 million from $153 million in the same period in 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and reduced amortization of regulatory assets.
Revenues
In the first nine months of 2009, revenues decreased by $382 million, or 14%, compared with the same period of 2008. The decrease in revenues is primarily due to a decrease in retail generation revenues ($131 million), wholesale generation revenues ($208 million), and distribution revenues ($39 million) in the first nine months of 2009.
Retail generation revenues decreased due to lower retail generation KWH sales in all sectors, partially offset by higher unit prices in the residential and commercial sectors resulting from the BGS auctions. Lower sales to the residential sector reflected milder weather in JCP&L’s service territory, while the decrease in sales to the commercial sector was primarily due to an increase in the number of shopping customers. Industrial sales were lower as a result of weakened economic conditions.
Changes in retail generation KWH sales and revenues by customer class in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | Decrease | | | | | | | Residential | | | (5.3) | % | Commercial | | | (19.7) | % | Industrial | | | (13.7) | % | Decrease in Generation Sales | | | (11.4) | % |
Retail Generation Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (15) | | Commercial | | | (104) | | Industrial | | | (12) | | Net Decrease in Generation Revenues | | $ | (131) | |
Wholesale generation revenues decreased $208 million in the first nine months of 2009 due to lower market prices and a decrease in sales volume from NUG purchases resulting from the termination of a NUG contract in October 2008.
Distribution revenues decreased $39 million in the first nine months of 2009 compared to the same period of 2008 due to lower KWH deliveries, reflecting weather and economic impacts in JCP&L’s service territory, partially offset by an increase in composite unit prices.
Changes in distribution KWH deliveries and revenues by customer class in the first nine months of 2009 compared to the same period in 2008 are summarized in the following tables:
Distribution KWH Deliveries | | Decrease | | | | | | | | Residential | | | | (5.3) | % | Commercial | | | | (3.9) | % | Industrial | | | | (13.1) | % | Decrease in Distribution Deliveries | | | | (5.6) | % |
Distribution Revenues | | Decrease | | | | (In millions) | | Residential | | $ | (25) | | Commercial | | | (10) | | Industrial | | | (4) | | Decrease in Distribution Revenues | | $ | (39) | |
Expenses
Total expenses decreased by $346 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year period by expense category:
Expenses - Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | (338 | ) | Other operating costs | | | 7 | | Provision for depreciation | | | 7 | | Amortization of regulatory assets | | | (18 | ) | General taxes | | | (4 | ) | Net decrease in expenses | | $ | (346 | ) |
Purchased power costs decreased in the first nine months of 2009 primarily due to the lower KWH sales requirements discussed above and lower unit prices due to reduced energy rates. Other operating costs increased in the first nine months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs. Depreciation expense increased due to an increase in depreciable property since the third quarter of 2008. Amortization of regulatory assets decreased in the first nine months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008. General taxes decreased principally as the result of lower Transitional Energy Facility Assessment (TEFA) and sales taxes.
Other Expenses
Other expenses increased by $9 million in the first nine months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with JCP&L's $300 million Senior Notes issuance in January 2009.
Sale of Investment
On April 17, 2008, JCP&L closed on the sale of its 86-MW Forked River Power Plant to Maxim Power Corp. for $20 million, as approved by an earlier order from the NJBPU. The New Jersey Rate Counsel appealed the sale to the Appellate Division of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.
METROPOLITAN EDISON COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also provides generation service to those customers electing to retain Met-Ed as their power supplier. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.
For additional information with respect to Met-Ed, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.
Results of Operations
Net income decreased to $37 million in the first nine months of 2009, compared to $64 million in the same period of 2008. The decrease was primarily due to increased amortization of regulatory assets, partially offset by lower other operating costs, purchased power and income taxes.
Revenues
Revenues increased by $5 million, or 0.4%, in the first nine months of 2009 compared to the same period of 2008 primarily due to higher distribution throughput revenues, partially offset by a decrease in retail generation and wholesale revenues. Wholesale revenues decreased by $7 million in the first nine months of 2009 due to lower wholesale KWH sales volume, partially offset by higher capacity prices for PJM market participants.
In the first nine months of 2009, retail generation revenues decreased $28 million due to lower KWH sales to all classes with a slight increase in composite unit prices in the residential and commercial customer classes and a slight decrease in composite unit prices in the industrial customer class. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory. Lower KWH sales in the residential sector were due to decreased weather-related usage, reflecting a 13.9% decrease in cooling degree days in the first nine months of 2009.
Changes in retail generation sales and revenues in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | (Decrease) | | | | | | | Residential | | | (2.0 | )% | Commercial | | | (4.7 | )% | Industrial | | | (11.9 | )% | Decrease in Retail Generation Sales | | | (5.6 | )% |
Retail Generation Revenues | | (Decrease) | | | | (In millions) | | Residential | | $ | (4 | ) | Commercial | | | (8 | ) | Industrial | | | (16 | ) | Decrease in Retail Generation Revenues | | $ | (28 | ) |
In the first nine months of 2009, distribution throughput revenues increased $63 million primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009. Decreased deliveries to commercial and industrial customers reflected the weakened economy, while decreased deliveries to residential customers were a result of the weather conditions described above.
Changes in distribution KWH deliveries and revenues in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables:
Distribution KWH Deliveries | | (Decrease) | | | | | | | Residential | | | (2.0 | )% | Commercial | | | (4.7 | )% | Industrial | | | (11.9 | )% | Decrease in Distribution Deliveries | | | (5.6 | )% |
Distribution Revenues | | Increase | | | | (In millions) | | Residential | | $ | 32 | | Commercial | | | 20 | | Industrial | | | 11 | | Increase in Distribution Revenues | | $ | 63 | |
Transmission service revenues decreased by $22 million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses increased by $44 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:
Expenses – Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | (17 | ) | Other operating costs | | | (129 | ) | Provision for depreciation | | | 5 | | Amortization of regulatory assets, net | | | 184 | | General taxes | | | 1 | | Net Increase in Expenses | | $ | 44 | |
The net amortization of regulatory assets increased by $184 million in the first nine months of 2009 compared to the same period of 2008 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs decreased $129 million in the first nine months of 2009 primarily due to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $17 million, or 2.5%, in the first nine months of 2009 due to reduced volumes purchased as a result of lower KWH sales requirements, partially offset by an increase in composite unit prices. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2008.
Other Expense
Other expense increased in the first nine months of 2009 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.
PENNSYLVANIA ELECTRIC COMPANY
ANALYSIS OF RESULTS OF OPERATIONS
Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.
For additional information with respect to Penelec, please see the information contained in FirstEnergy's Management Discussion and Analysis of Financial Condition and Results of Operations above under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances and Outlook.
Results of Operations
Net income decreased to $49 million in the first nine months of 2009, compared to $62 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and decreased amortization of regulatory assets.
Revenues
Revenues decreased by $61 million, or 5.4%, in the first nine months of 2009 primarily due to lower retail generation revenues, distribution throughput revenues and transmission revenues, partially offset by higher wholesale generation revenues. Wholesale revenues increased $1 million in the first nine months of 2009, compared to the same period of 2008, primarily reflecting higher KWH sales.
In the first nine months of 2009, retail generation revenues decreased $31 million primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions; reduced KWH sales to the residential customer class were due to decreased weather-related usage, reflecting a 28.5% decrease in cooling degree days in the first nine months of 2009.
Changes in retail generation sales and revenues in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables:
Retail Generation KWH Sales | | (Decrease) | | | | | | Residential | | | (1.4) | % | Commercial | | | (3.2) | % | Industrial | | | (16.2) | % | Decrease in Retail Generation Sales | | | (6.6) | % |
| | | | Retail Generation Revenues | | (Decrease) | | | | (In millions) | | Residential | | $ | (2) | | Commercial | | | (6) | | Industrial | | | (23) | | Decrease in Retail Generation Revenues | | $ | (31) | |
Revenues from distribution throughput decreased $2 million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased deliveries to the commercial and industrial sectors reflecting the economic conditions in Penelec's service area. Offsetting this decrease was an increase in residential unit prices due to an increase in transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2009.
Changes in distribution KWH deliveries and revenues in the first nine months of 2009 compared to the same period of 2008 are summarized in the following tables:
Distribution KWH Deliveries | | (Decrease) | | | | | | Residential | | | (1.4) | % | Commercial | | | (3.2) | % | Industrial | | | (15.4) | % | Decrease in Distribution Deliveries | | | (6.6) | % |
Distribution Revenues | | Increase (Decrease) | | | | (In millions) | | Residential | | $ | 4 | | Commercial | | | (2 | ) | Industrial | | | (4 | ) | Net Decrease in Distribution Revenues | | $ | (2 | ) |
Transmission revenues decreased by $34 million in the first nine months of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.
Operating Expenses
Total operating expenses decreased by $27 million in the first nine months of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:
Expenses - Changes | | Increase (Decrease) | | | | (In millions) | | Purchased power costs | | $ | (11 | ) | Other operating costs | | | (5 | ) | Provision for depreciation | | | 5 | | Amortization of regulatory assets, net | | | (11 | ) | General taxes | | | (5 | ) | Net Decrease in Expenses | | $ | (27 | ) |
Purchased power costs decreased by $11 million, or 1.7%, in the first nine months of 2009 compared to the same period of 2008 due to reduced volume as a result of lower KWH sales requirements, partially offset by increased composite unit prices. Other operating costs decreased by $5 million in the first nine months of 2009 due primarily to reduced labor and transmission expenses and a decrease in contingency reserves based on a favorable legal ruling, partially offset by higher pension and OPEB expenses. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2008. The net amortization of regulatory assets decreased in the first nine months of 2009 primarily due to increased transmission cost deferrals as a result of increased net congestion costs. General taxes decreased due to lower gross receipts tax due to the reduced KWH sales mentioned above.
Other Expense
In the first nine months of 2009, other expense decreased primarily due to lower interest expense on borrowings from the regulated money pool combined with reduced interest expense on long-term debt due to the $100 million repayment of unsecured notes in April 2009.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See “Management’s"Management's Discussion and Analysis of Financial Condition and Results of Operations – Market Risk Information”Information" in Item 2 above.
ITEM 4. CONTROLS AND PROCEDURES
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY
FirstEnergy’sFirstEnergy's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures arewere effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31,September 30, 2009, there were no changes in FirstEnergy’sFirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant’sregistrant's internal control over financial reporting.
ITEM 4T. CONTROLS AND PROCEDURES – FES, OE, CEI, TE, JCP&L, MET-ED AND PENELEC
(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Each registrant's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures arewere effective as of the end of the period covered by this report.
(b) CHANGES IN INTERNAL CONTROLS
During the quarter ended March 31,September 30, 2009, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 89 and 910 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q. ITEM 1A. RISK FACTORS
FirstEnergy’sFirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008, includesand Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and June 30, 2009, include a detailed discussion of its risk factors. The information presented below updates certain of thoseFor the quarter ended September 30, 2009, there have been no material changes to these risk factors and should be read in conjunction with the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K.
FES’ Business is Affected By Competitive Procurement Processes Approved by State Regulators
The adoption of competitive bid processes for PLR generation supply in Ohio and Pennsylvania may affect the amount of generation that FES sells to its utility affiliates in those states. For example, the Amended ESP approved by the PUCO established a competitive bid process for generation supply and pricing for a two-year period beginning June 1, 2009 through May 31, 2011. FES intends to participate in the CBP as a supplier and its results of operations and financial condition will be impacted by the price and the percentage of the load for which it is ultimately the supplier.
Competitive Power Markets
FES’ financial performance depends upon its success in competing in wholesale and retail markets in MISO and PJM. FES’ ability to compete successfully in these markets is affected by, among other things, the efficiency and cost structure of its generation fleet, market prices, demand for electricity, effectiveness of risk management practices and the market rules established by state and federal regulators.factors.
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 firstthird quarter of 2009.
| | Period | | | Period | | | | | January | | February | | March | | First Quarter | | | July | | August | | September | | Third Quarter | | Total Number of Shares Purchased (a) | Total Number of Shares Purchased (a) | | 23,535 | | 20,090 | | 887,792 | | 931,417 | | | 30,128 | | 108,110 | | 367,075 | | 505,313 | | Average Price Paid per Share | Average Price Paid per Share | | $50.09 | | $46.20 | | $41.34 | | $41.67 | | | $39.05 | | $45.21 | | $45.46 | | $45.02 | | Total Number of Shares Purchased | Total Number of Shares Purchased | | | | | | | | | | | | | | | | | | | As Part of Publicly Announced Plans | As Part of Publicly Announced Plans | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Maximum Number (or Approximate Dollar | Maximum Number (or Approximate Dollar | | | | | | | | | | | | | | | | | | | Value) of Shares that May Yet Be | Value) of Shares that May Yet Be | | | | | | | | | | | | | | | | | | | Purchased Under the Plans or Programs | Purchased Under the Plans or Programs | | - | | - | | - | | - | | | - | | - | | - | | - | |
(a) | Share amounts reflect purchases on the open market to satisfy FirstEnergy's obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan, and shares purchased as part of publicly announced plans.Plan. |
ITEM 5. OTHER INFORMATION
On November 3, 2009, FirstEnergy Solutions Corp. (FES), Met-Ed, Penelec and Waverly executed a Fourth Restated Partial Requirements Agreement (Fourth PRA) effective January 1, 2010. The Fourth PRA supersedes the Third Restated Partial Requirements Agreement executed November 1, 2008, among the parties. The Fourth PRA also terminates the call options provided under the Third Restated Partial Requirements Agreement. The Fourth PRA continues to limit the amount of capacity resources supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s (Buyers) energy requirements in 2010 Under the Fourth PRA, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases from a third party, non-affiliated supplier to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply under the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010. The foregoing summary does not purport to be complete and is qualified in its entirety by reference to the Fourth Restated Partial Requirements Agreements filed as an exhibit to this Form 10-Q.
ITEM 6. EXHIBITS
Exhibit Number | | | | | | | | | FirstEnergy | | | | 10.1 | Form of Director Indemnification Agreement | | | 10.2 | Form of Management Director Indemnification Agreement | | | 12 | Fixed charge ratios | | | 15 | Letter from independent registered public accounting firm | | | 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 FirstEnergy Corp. for the three months ended March 31, 2009, 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. | | FES | | | 4.1 | Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, of FirstEnergy Generation Corp. to The Bank of New York Trust Company, N.A., as Trustee | | 4.1(a) | First Supplemental Indenture dated as of June 25, 2008 providing among other things for First Mortgage Bonds, Guarantee Series A of 2008 due 2009 and First Mortgage Bonds, Guarantee Series B of 2008 due 2009 | | 4.1(b) | Second Supplemental Indenture dated as of March 1, 2009 providing among other things for First Mortgage Bonds, Guarantee Series A of 2009 due 2014 and First Mortgage Bonds, Guarantee Series B of 2009 due 2023 | | 4.1(c) | Third Supplemental Indenture dated as of March 31, 2009 providing among other things for First Mortgage Bonds, Collateral Series A of 2009 due 2011 | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | OE | | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | CEI | 101* | The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2009, 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. | FES | | | 3.1 | Amended and Restated Code of Regulations of FirstEnergy Solutions Corp. effective as of August 26, 2009 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 3.1) | | 4.1 | Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.1) | | 4.2 | First Supplemental Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2) | | 4.3 | Form of 4.80% Senior Notes due 2015 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2) | | 4.4 | Form of 6.05% Senior Notes due 2021 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2) | | 4.5 | Form of 6.80% Senior Notes due 2039 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2) | | 10.1 | Registration Rights Agreement, dated August 7, 2009, among FirstEnergy Solutions Corp., and Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC and RBS Securities Inc., as representatives of the initial purchasers (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 10.1) | | 10.2 | The Fourth Restated Partial Requirements Agreement | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | OE | | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 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 | TECEI | | | 4.1 | FirstNinetieth Supplemental Indenture, dated as of April 24,August 1, 2009, between the Toledo Edison Companyto The Cleveland Electric Illuminating Company’s Mortgage and The BankDeed of New York Mellon Trust Company, N.A., as trustee to the Indenture dated as of NovemberJuly 1, 20061940 (incorporated by reference to April 24,CEI's Form 8-K filed on August 18, 2009 Form 8-K,(SEC File No. 1-2323), Exhibit 4.1) | | 4.2 | Officer’s Certificate (including the Form of the 7.25% Senior Secured Notes due 2020), dated April 24, 2009 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.2) | | 4.3 | Fifty-sixth Supplemental Indenture, dated as of April 23, 2009, between The Toledo Edison Company and JPMorgan Chase Bank, N.A., as trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.3) | | 4.4 | Fifty-seventh Supplemental Indenture, dated as of April 24, 2009, between the Toledo Edison Company and The Bank of New York Mellon Trust Company, N.A., as successor trustee, to the Indenture of Mortgage and Deed of Trust dated as of April 1, 1947 (incorporated by reference to April 24, 2009 Form 8-K, Exhibit 4.4) | | 4.5 | Form of First Mortgage Bonds, 7.25%5.50% Series of 2009 Due 2020due 2024 (incorporated by reference to April 24, 2009CEI's Form 8-K filed on August 18, 2009 (SEC File No. 1-2323), Exhibit 4.5) | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 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 | JCP&L | 4.1) | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
Met-EdTE | | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 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 | PenelecJCP&L | | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | Met-Ed | | | 10.2 | The Fourth Restated Partial Requirements Agreement | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 | Penelec | | | 4.1 | Company Order, dated as of September 30, 2009 establishing the terms of the 5.20% Senior Notes due 2020 and 6.15% Senior Notes due 2038 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1) | | 4.2 | Form of 5.20% Senior Notes due 2020 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1) | | 4.3 | Form of 6.15% Senior Notes due 2038 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1) | | 4.4 | Supplemental Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of April 1, 2009, as amended, between Pennsylvania Electric Company and The Bank of New York Mellon, as successor trustee (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.4) | | 4.5 | Agreement of Resignation, Appointment and Acceptance among The Bank of New York Mellon, as Resigning Trustee, The Bank of New York Mellon Trust Company, N.A., as Successor Trustee and Pennsylvania Electric Company, dated October 1, 2009 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.5) | | 10.2 | The Fourth Restated Partial Requirements Agreement | | 12 | Fixed charge ratios | | 15 | Letter from independent registered public accounting firm | | 31.1 | Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a) | | 31.2 | Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a) | | 32 | Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350 |
* Users of this data are advised pursuant to Rule 401 of Regulation S-T that the financial information contained in the XBRL-Related Documents is unaudited and the purpose of submitting these XBRL-Related Documents is to test the related format and technology and, as a result, investors should not rely on the XBRL-Related Documents in making investment decisions. Furthermore, users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the Securities and Exchange Commission that this Interactive Data File is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, as amended, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, as amended, and otherwise is not subject to liability under these sections.
Pursuant to reporting requirements of respective financings, FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec are required to file fixed charge ratios as an exhibit to this Form 10-Q.
Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE, CEI, TE, JCP&L, Met-Ed nor Penelec have filed as an exhibit to this Form 10-Q any instrument with respect to long-term debt if the respective total amount of securities authorized thereunder does not exceed 10% of its respective total assets, but each hereby agrees to furnish to the SEC on request any such documents.
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, each Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
May 7,November 6, 2009
| FIRSTENERGY CORP. CORP. | | Registrant | | | | FIRSTENERGY SOLUTIONS CORP. | | Registrant | | | | OHIO EDISON COMPANY | | Registrant | | | | THE CLEVELAND ELECTRIC | | ILLUMINATING COMPANY | | Registrant | | | | THE TOLEDO EDISON COMPANY | | Registrant | | | | METROPOLITAN EDISON COMPANY | | Registrant | | | | PENNSYLVANIA ELECTRIC COMPANY | | Registrant |
| | | Harvey L. Wagner | | Vice President, Controller | | and Chief Accounting Officer |
| JERSEY CENTRAL POWER & LIGHT COMPANY | | Registrant | | | | | | | | /s/ PauletteKevin R. ChatmanBurgess | | PauletteKevin R. ChatmanBurgess | | Controller | | (Principal Accounting Officer) |
|