1.0.0.3 false Notes to Financial Statements (Unaudited) false 1 $ false true false Unaudited false Unaudited scenarioName asi http://www.firstenergycorp.com/20090507 u000 Standard http://www.xbrl.org/2003/iso4217 USD iso4217 0 u001 Standard http://www.xbrl.org/2003/instance pure xbrli 0 u002 Standard http://www.xbrl.org/2003/instance shares xbrli 0 2 Notes to Financial Statements 0 fe_NotesToFinancialStatements fe false na duration string No definition available. false false false false false true false false false 1 false false 0 0 false true No definition available. false 3 Organization, Consolidation and Presentation of Financial Statements Disclosure [Text Block] 1 us-gaap_OrganizationConsolidationAndPresentationOfFinancialStatementsDisclosureTextBlock us-gaap true na duration string Description containing the entire organization, consolidation and basis of presentation of financial statements disclosure. false false false false false false false false false 1 false false 0 0 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. 1. ORGANIZATION AND BASIS OF PRESENTATION FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common false true Description containing the entire organization, consolidation and basis of presentation of financial statements disclosure. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Research Bulletin (ARB) -Number 51 -Paragraph 2-6 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Statement of Position (SOP) -Number 94-6 -Paragraph 10 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name FASB Interpretation (FIN) -Number 46R -Paragraph 4, 14, 15 false 4 Schedule of Earnings Per Share, Basic, by Common Class [Text Block] 1 us-gaap_ScheduleOfEarningsPerShareBasicByCommonClassTextBlock us-gaap true na duration string This element may be used to capture the complete disclosure pertaining to an entity's basic earnings per share. false false false false false false false false false 1 false false 0 0 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: THREE MONTHS ENDEDRECONCILIATION OF BASIC AND DILUTED 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 304Assumed exercise of dilutive stock options and awards 2 3Average 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 2. EARNINGS PER SHARE Basic earnings per share of common stock is computed using the weighted average of actual common shares outstanding during the false true This element may be used to capture the complete disclosure pertaining to an entity's basic earnings per share. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 128 -Paragraph 40 false 5 Fair Value Disclosures [Text Block] 1 us-gaap_FairValueDisclosuresTextBlock us-gaap true na duration string This item represents the complete disclosure regarding the fair value of financial instruments (as defined), including... false false false false false false false false false 1 false false 0 0 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 MEASURESAS 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. 3. FAIR VALUE MEASURES FirstEnergy's valuation techniques, including the three levels of the fair value hierarchy as defined by SFAS 157, are false true This item represents the complete disclosure regarding the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments, assets, and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the Company is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risk is are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 107 -Paragraph 15B -Subparagraph a, b Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 107 -Paragraph 3, 10, 14, 15 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 133 -Paragraph 44A, 44B Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 157 -Paragraph 32, 33, 34 Reference 5: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 107 -Paragraph 15C, 15D Reference 6: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 107 -Paragraph 15A -Subparagraph a-d Reference 7: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 159 -Paragraph 17-22, 27, 28 false 6 Derivative Instruments and Hedging Activities Disclosure [Text Block] 1 us-gaap_DerivativeInstrumentsAndHedgingActivitiesDisclosureTextBlock us-gaap true na duration string Description of risk management strategies, derivatives in hedging activities and nonhedging derivative instruments, the... false false false false false false false false false 1 false false 0 0 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 MARCH 31 -------- 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 $ 27Natural Gas Futures Natural Gas Futures Current Assets - - Current Liabilities 11 4 Long-Term Deferred Charges - - Noncurrent Liabilities 5 5Other 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 LiabilityOther 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 GallonsNatural Gas Futures 4,850 - 4,850mmBtu 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. DERIVATIVESNOT 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 ) - -2008Unrealized 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. 4. DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for false true Description of risk management strategies, derivatives in hedging activities and nonhedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 133 -Paragraph 44, 45, 46, 47 false 7 Pension and Other Postretirement Benefits Disclosure [Text Block] 1 us-gaap_PensionAndOtherPostretirementBenefitsDisclosureTextBlock us-gaap true na duration string Description containing the entire pension and other postretirement benefits disclosure as a single block of text. false false false false false false false false false 1 false false 0 0 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) -------------Service cost $ 22 $ 22 $ 5 $ - - - 5 Interest cost 80 75 20 18Expected return on plan assets (81 ) (116 ) - -(9 ) (13 ) - -Amortization of prior service cost 3 3(38 ) (37 ) - - Recognized net actuarial loss 42 2 16 12 Net periodic cost (credit) $ 66 $ (14 ) $ -------------------------- - -- - --- - -(6 ) $ (15 )-- - - --- - 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: OTHER POSTRETIREMENT PENSION BENEFIT COST (CREDIT) BENEFIT COST (CREDIT) ============================= 2009 2008 2009 2008 ---- ---- ---- (IN MILLIONS) -------------FES $ 18 $ 5 $ (1 ) $ (2)OE 7 (6 ) (2 ) (2 ) CEI 5 (1 ) 1 1 TE 2 (1 ) 1 1JCP&L 9 (3 ) (1 ) (4 )Met-Ed 6 (2 ) (1 ) (3)Penelec 4 (3 ) - (3 ) Other FirstEnergy subsidiaries 15 (3 )(3 ) (3 ) $ 66 $ (14 ) $ (6 ) $ (15) - -- - --- - -- - --- 5. PENSION AND OTHER POSTRETIREMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all false true Description containing the entire pension and other postretirement benefits disclosure as a single block of text. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 106 -Paragraph 74, 77, 78, 518 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 158 -Paragraph 7, 21, 22 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name FASB Staff Position (FSP) -Number FAS106-2 -Paragraph 20, 21, 22 Reference 4: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 87 -Paragraph 54, 56, 264 Reference 5: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 132R -Paragraph 5, 6, 7 Reference 6: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Emerging Issues Task Force (EITF) -Number 03-02 -Paragraph 8 Reference 7: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 88 -Paragraph 17, 48 false 8 Schedule of Variable Interest Entities [Text Block] 1 us-gaap_ScheduleOfVariableInterestEntitiesTextBlock us-gaap true na duration string Disclosure of variable interest entities (VIE), including, but not limited to the nature, purpose, size, and activities of... false false false false false false false false false 1 false false 0 0 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) ------------- JCP&L $ 19 $ 19 Met-Ed 15 16 Penelec 9 8 $ 43 $ 43 - -- - -- 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. 6. VARIABLE INTEREST ENTITIES FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary as defined by false true Disclosure of variable interest entities (VIE), including, but not limited to the nature, purpose, size, and activities of the VIE, the carrying amount and classification of consolidated assets that are collateral for the VIE's obligations, lack of recourse if creditors (or beneficial interest holders) of a consolidated VIE have no recourse to the general credit of the primary beneficiary. An enterprise that holds a significant variable interest in a VIE but is not the primary beneficiary may disclose the nature of its involvement with the VIE and when that involvement began, the nature, purpose, size, and activities of the VIE and the enterprise's maximum exposure to loss as a result of its involvement with the VIE. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name FASB Interpretation (FIN) -Number 46R -Paragraph 2, 14, 15, 16, 23, 24, 25, 26 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name FASB Interpretation (FIN) -Number 46R -Paragraph 4 -Subparagraph g Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 140 -Paragraph 35 false 9 Income Tax Disclosure [Text Block] 1 us-gaap_IncomeTaxDisclosureTextBlock us-gaap true na duration string Description containing the entire income tax disclosure. Examples include net deferred tax liability or asset recognized in... false false false false false false false false false 1 false false 0 0 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. 7. INCOME TAXES FirstEnergy accounts for uncertainty in income taxes recognized in a company's financial statements in accordance with FIN 48. This false true Description containing the entire income tax disclosure. Examples include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information. This element may be used as a single block of text to encapsulate the entire disclosure including data and tables. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 08 -Paragraph (h) -Article 4 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 109 -Paragraph 136, 172 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 109 -Paragraph 43, 44, 45, 46, 47, 48, 49 false 10 Commitments and Contingencies Disclosure [Text Block] 1 us-gaap_CommitmentsAndContingenciesDisclosureTextBlock us-gaap true na duration string Includes disclosure of commitments and contingencies. This element may be used as a single block of text to encapsulate the... false false false false false false false false false 1 false false 0 0 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (A) GUARANTEES AND OTHER ASSURANCES As part of normal business activities, FirstEnergy enters into variousagreements on behalf of its subsidiaries to provide financial or performanceassurances to third parties. These agreements include contract guarantees,surety bonds and LOCs. As of March 31, 2009, outstanding guarantees and otherassurances aggregated approximately $4.5 billion, consisting of parentalguarantees - $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 subsidiariesinvolved in energy commodity activities principally to facilitate or hedgenormal physical transactions involving electricity, gas, emission allowances andcoal. FirstEnergy also provides guarantees to various providers of creditsupport for the financing or refinancing by subsidiaries of costs related to theacquisition of property, plant and equipment. These agreements obligateFirstEnergy to fulfill the obligations of those subsidiaries directly involvedin energy and energy-related transactions or financing where the law mightotherwise limit the counterparties' claims. If demands of a counterparty were toexceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfiedby other FirstEnergy assets. The likelihood is remote that such parentalguarantees of $0.4 billion (included in the $1.2 billion discussed above) as ofMarch 31, 2009 would increase amounts otherwise payable by FirstEnergy to meetits obligations incurred in connection with financings and ongoing energy andenergy-related activities. While these types of guarantees are normally parental commitments for the futurepayment of subsidiary obligations, subsequent to the occurrence of a creditrating downgrade or "material adverse event," the immediate posting of cashcollateral, provision of an LOC or accelerated payments may be required of thesubsidiary. As of March 31, 2009, FirstEnergy's maximum exposure under thesecollateral provisions was $761 million, consisting of $55 million due to"material adverse event" contractual clauses and $706 million due to a belowinvestment grade credit rating. Additionally, stress case conditions of a creditrating downgrade or "material adverse event" and hypothetical adverse pricemovements in the underlying commodity markets would increase this amount to $830million, consisting of $54 million due to "material adverse event" contractualclauses and $776 million due to a below investment grade credit rating. Most of FirstEnergy's surety bonds are backed by various indemnities commonwithin the insurance industry. Surety bonds and related guarantees of $111million provide additional assurance to outside parties that contractual andstatutory obligations will be met in a number of areas including constructioncontracts, environmental commitments and various retail transactions. In addition to guarantees and surety bonds, FES' contracts, including powercontracts with affiliates awarded through competitive bidding processes,typically contain margining provisions which require the posting of cash or LOCsin amounts determined by future power price movements. Based on FES' contractsas of March 31, 2009, and forward prices as of that date, FES had $205 millionof outstanding collateral payments. Under a hypothetical adverse change inforward prices (15% decrease in the first 12 months and 20% decrease in pricesthereafter), FES would be required to post an additional $77 million. Dependingon the volume of forward contracts entered and future price movements, FES couldbe 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 unconditionallyguaranteed all of FGCO's obligations under each of the leases (see Note 12). Therelated lessor notes and pass through certificates are not guaranteed by FES orFGCO, but the notes are secured by, among other things, each lessor trust'sundivided interest in Unit 1, rights and interests under the applicable leaseand rights and interests under other related agreements, including FES' leaseguaranty. On October 8, 2008, to enhance their liquidity position in the face of theturbulent credit and bond markets, FirstEnergy, FES and FGCO entered into a $300million secured term loan facility with Credit Suisse. Under the facility, FGCOis the borrower and FES and FirstEnergy are guarantors. Generally, the facilityis 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 toair and water quality and other environmental matters. The effects of complianceon FirstEnergy with regard to environmental matters could have a materialadverse effect on FirstEnergy's earnings and competitive position to the extentthat it competes with companies that are not subject to such regulations and,therefore, do not bear the risk of costs associated with compliance, or failureto comply, with such regulations. FirstEnergy estimates capital expenditures forenvironmental compliance of approximately $808 million for the period 2009-2013. FirstEnergy accrues environmental liabilities only when it concludes that it isprobable that it has an obligation for such costs and can reasonably estimatethe amount of such costs. Unasserted claims are reflected in FirstEnergy'sdetermination of environmental liabilities and are accrued in the period thatthey 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 unitinvolved and/or civil or criminal penalties of up to $37,500 for each day theunit is in violation. The EPA has an interim enforcement policy for SO2regulations in Ohio that allows for compliance based on a 30-day averagingperiod. FirstEnergy believes it is currently in compliance with this policy, butcannot predict what action the EPA may take in the future with respect to theinterim enforcement policy. The EPA Region 5 issued a Finding of Violation and NOV to the Bay Shore PowerPlant dated June 15, 2006, alleging violations to various sections of the CAA.FirstEnergy has disputed those alleged violations based on its CAA permit, theOhio SIP and other information provided to the EPA at an August 2006 meetingwith the EPA. The EPA has several enforcement options (administrative complianceorder, administrative penalty order, and/or judicial, civil or criminal action)and has indicated that such option may depend on the time needed to achieve anddemonstrate compliance with the rules alleged to have been violated. On June 5,2007, the EPA requested another meeting to discuss "an appropriate complianceprogram" and a disagreement regarding emission limits applicable to the commonstack for Bay Shore Units 2, 3 and 4. FirstEnergy complies with SO2 reduction requirements under the Clean Air ActAmendments of 1990 by burning lower-sulfur fuel, generating more electricityfrom lower-emitting plants, and/or using emission allowances. NOX reductionsrequired by the 1990 Amendments are being achieved through combustion controls,the generation of more electricity at lower-emitting plants, and/or usingemission allowances. In September 1998, the EPA finalized regulations requiringadditional NOX reductions at FirstEnergy's facilities. The EPA's NOX TransportRule imposes uniform reductions of NOX emissions (an approximate 85% reductionin utility plant NOX emissions from projected 2007 emissions) across a region ofnineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and theDistrict of Columbia based on a conclusion that such NOX emissions arecontributing significantly to ozone levels in the eastern United States.FirstEnergy believes its facilities are also complying with the NOX budgetsestablished under SIPs through combustion controls and post-combustion controls,including Selective Catalytic Reduction and SNCR systems, and/or using emissionallowances. In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaintagainst 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 NSRcases. 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 theSammis NSR litigation was approved by the Court on July 11, 2005. Thissettlement agreement, in the form of a consent decree, requires reductions ofNOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-firedplants through the installation of pollution control devices or repowering andprovides for stipulated penalties for failure to install and operate suchpollution controls or complete repowering in accordance with that agreement.Capital expenditures necessary to complete requirements of the Sammis NSRLitigation consent decree, including repowering Burger Units 4 and 5 for biomassfuel 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 daysprior to the filing of a citizen suit under the federal CAA, alleging violationsof air pollution laws at the Bruce Mansfield Plant, including opacitylimitations. Prior to the receipt of this notice, the Plant was subject to aConsent Order and Agreement with the Pennsylvania Department of EnvironmentalProtection concerning opacity emissions under which efforts to achievecompliance with the applicable laws will continue. On October 18, 2007,PennFuture filed a complaint, joined by three of its members, in the UnitedStates 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 thatmonetary damages could not be recovered under the public nuisance claim. In July2008, three additional complaints were filed against FGCO in the United StatesDistrict Court for the Western District of Pennsylvania seeking damages based onBruce Mansfield Plant air emissions. In addition to seeking damages, two of thecomplaints seek to enjoin the Bruce Mansfield Plant from operating except in a"safe, responsible, prudent and proper manner", one being a complaint filed onbehalf of twenty-one individuals and the other being a class action complaint,seeking certification as a class action with the eight named plaintiffs as theclass representatives. On October 14, 2008, the Court granted FGCO's motion toconsolidate discovery for all four complaints pending against the BruceMansfield Plant. FGCO believes the claims are without merit and intends todefend itself against the allegations made in these complaints. The PennsylvaniaDepartment of Health and the U.S. Agency for Toxic Substance and DiseaseRegistry recently disclosed their intention to conduct additional air monitoringin the vicinity of the Mansfield plant. On December 18, 2007, the state of New Jersey filed a CAA citizen suit allegingNSR violations at the Portland Generation Station against Reliant (the currentowner and operator), Sithe Energy (the purchaser of the Portland Station fromMet-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 withoutpreconstruction NSR or permitting under the CAA's prevention of significantdeterioration program, and seeks injunctive relief, penalties, attorney fees andmitigation of the harm caused by excess emissions. On March 14, 2008, Met-Edfiled a motion to dismiss the citizen suit claims against it and a stipulationin 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, whichthe Court granted on March 24, 2009. On December 5, 2008, New Jersey filed anamended complaint, adding claims with respect to alleged modifications thatoccurred after GPU's sale of the plant. Met-Ed filed a Motion to Dismiss theclaims 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 atthe 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 andShawville Stations based on "modifications" dating back to 1984. JCP&L, as theformer owner of 16.67% of Keystone Station and Penelec, as former owner andoperator of the Shawville Station, are unable to predict the outcome of thismatter. On June 11, 2008, the EPA issued a Notice and Finding of Violation to MissionEnergy Westside, Inc. alleging that "modifications" at the Homer City PowerStation occurred since 1988 to the present without preconstruction NSR orpermitting under the CAA's prevention of significant deterioration program.Mission Energy is seeking indemnification from Penelec, the co-owner (along withNew York State Electric and Gas Company) and operator of the Homer City PowerStation prior to its sale in 1999. The scope of Penelec's indemnity obligationto and from Mission Energy is disputed. Penelec is unable to predict the outcomeof this matter. On May 16, 2008, FGCO received a request from the EPA for information pursuantto Section 114(a) of the CAA for certain operating and maintenance informationregarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants toallow the EPA to determine whether these generating sources are complying withthe NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered intoan Administrative Consent Order modifying that request and setting forth aschedule for FGCO's response. On October 27, 2008, FGCO received a secondrequest from the EPA for information pursuant to Section 114(a) of the CAA foradditional operating and maintenance information regarding the Eastlake,Lakeshore, Bay Shore and Ashtabula generating plants. FGCO intends to fullycomply with the EPA's information requests, but, at this time, is unable topredict the outcome of this matter. On August 18, 2008, FirstEnergy received a request from the EPA for informationpursuant to Section 114(a) of the CAA for certain operating and maintenanceinformation 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 sourcesare complying with the NSR provisions of the CAA. FirstEnergy intends to fullycomply with the EPA's information request, but, at this time, is unable topredict 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 ofColumbia based on proposed findings that air emissions from 28 eastern statesand the District of Columbia significantly contribute to non-attainment of theNAAQS for fine particles and/or the "8-hour" ozone NAAQS in other states. CAIRrequires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 forNOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately cappingSO2 emissions in affected states to just 2.5 million tons annually and NOXemissions to just 1.3 million tons annually. CAIR was challenged in the UnitedStates Court of Appeals for the District of Columbia and on July 11, 2008, theCourt vacated CAIR "in its entirety" and directed the EPA to "redo its analysisfrom the ground up." On September 24, 2008, the EPA, utility, mining and certainenvironmental advocacy organizations petitioned the Court for a rehearing toreconsider its ruling vacating CAIR. On December 23, 2008, the Courtreconsidered its prior ruling and allowed CAIR to remain in effect to"temporarily preserve its environmental values" until the EPA replaces CAIR witha new rule consistent with the Court's July 11, 2008 opinion. The future cost ofcompliance 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 ofregulations regarding hazardous air pollutants from electric power plants,identifying mercury as the hazardous air pollutant of greatest concern. In March2005, the EPA finalized the CAMR, which provides a cap-and-trade program toreduce mercury emissions from coal-fired power plants in two phases; initially,capping national mercury emissions at 38 tons by 2010 (as a "co-benefit" fromimplementation of SO2 and NOX emission caps under the EPA's CAIR program) and 15tons per year by 2018. Several states and environmental groups appealed the CAMRto the United States Court of Appeals for the District of Columbia. On February8, 2008, the Court vacated the CAMR, ruling that the EPA failed to take thenecessary steps to "de-list" coal-fired power plants from its hazardous airpollutant program and, therefore, could not promulgate a cap-and-trade program.The EPA petitioned for rehearing by the entire Court, which denied the petitionon May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitionedthe 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. OnFebruary 23, 2009, the Supreme Court dismissed the EPA's petition and denied theindustry group's petition. The EPA is developing new mercury emission standardsfor coal-fired power plants. FGCO's future cost of compliance with mercuryregulations may be substantial and will depend on the action taken by the EPAand on how they are ultimately implemented. Pennsylvania has submitted a new mercury rule for EPA approval that does notprovide a cap-and-trade approach as in the CAMR, but rather follows acommand-and-control approach imposing emission limits on individual sources. OnJanuary 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania'smercury rule "unlawful, invalid and unenforceable" and enjoined the Commonwealthfrom continued implementation or enforcement of that rule. It is anticipatedthat compliance with these regulations, if the Commonwealth Court's rulings werereversed on appeal and Pennsylvania's mercury rule was implemented, would notrequire 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 Japanadopted an agreement, the Kyoto Protocol, to address global warming by reducingthe amount of man-made GHG, including CO2, emitted by developed countries by2012. The United States signed the Kyoto Protocol in 1998 but it was neversubmitted for ratification by the United States Senate. However, the Bushadministration had committed the United States to a voluntary climate changestrategy to reduce domestic GHG intensity - the ratio of emissions to economicoutput - by 18% through 2012. Also, in an April 16, 2008 speech, formerPresident Bush set a policy goal of stopping the growth of GHG emissions by2025, as the next step beyond the 2012 strategy. In addition, the EPACTestablished a Committee on Climate Change Technology to coordinate federalclimate change activities and promote the development and deployment of GHGreducing technologies. President Obama has announced his Administration's "NewEnergy for America Plan" that includes, among other provisions, ensuring that10% 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-tradeprogram to reduce GHG emissions 80% by 2050. There are a number of initiatives to reduce GHG emissions under consideration atthe federal, state and international level. At the international level, effortsto reach a new global agreement to reduce GHG emissions post-2012 have begunwith the Bali Roadmap, which outlines a two-year process designed to lead to anagreement in 2009. At the federal level, members of Congress have introducedseveral bills seeking to reduce emissions of GHG in the United States, and theSenate Environment and Public Works Committee has passed one such bill. Stateactivities, primarily the northeastern states participating in the RegionalGreenhouse Gas Initiative and western states, led by California, havecoordinated efforts to develop regional strategies to control emissions ofcertain GHGs. On April 2, 2007, the United States Supreme Court found that the EPA has theauthority to regulate CO2 emissions from automobiles as "air pollutants" underthe CAA. Although this decision did not address CO2 emissions from electricgenerating plants, the EPA has similar authority under the CAA to regulate "airpollutants" from those and other facilities. On April 17, 2009, the EPA releaseda "Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gasesunder the Clean Air Act." The EPA's proposed finding concludes that theatmospheric concentrations of several key greenhouse gases threaten the healthand welfare of future generations and that the combined emissions of these gasesby motor vehicles contribute to the atmospheric concentrations of these keygreenhouse gases and hence to the threat of climate change. Although the EPA'sproposed finding, if finalized, does not establish emission requirements formotor vehicles, such requirements would be expected to occur through furtherrulemakings. Additionally, while the EPA's proposed findings do not specificallyaddress stationary sources, including electric generating plants, thosefindings, if finalized, would be expected to support the establishment of futureemission requirements by the EPA for stationary sources. FirstEnergy cannot currently estimate the financial impact of climate changepolicies, although potential legislative or regulatory programs restricting CO2emissions could require significant capital and other expenditures. The CO2emissions per KWH of electricity generated by FirstEnergy is lower than manyregional competitors due to its diversified generation sources, which includelow or non-CO2 emitting gas-fired and nuclear generators. Clean Water Act Various water quality regulations, the majority of which are the result of thefederal Clean Water Act and its amendments, apply to FirstEnergy's plants. Inaddition, Ohio, New Jersey and Pennsylvania have water quality standardsapplicable to FirstEnergy's operations. As provided in the Clean Water Act,authority to grant federal National Pollutant Discharge Elimination System waterdischarge permits can be assumed by a state. Ohio, New Jersey and Pennsylvaniahave assumed such authority. On September 7, 2004, the EPA established new performance standards underSection 316(b) of the Clean Water Act for reducing impacts on fish and shellfishfrom cooling water intake structures at certain existing large electricgenerating plants. The regulations call for reductions in impingement mortality(when aquatic organisms are pinned against screens or other parts of a coolingwater intake system) and entrainment (which occurs when aquatic life is drawninto a facility's cooling water system). On January 26, 2007, the United StatesCourt of Appeals for the Second Circuit remanded portions of the rulemakingdealing with impingement mortality and entrainment back to the EPA for furtherrulemaking and eliminated the restoration option from the EPA's regulations. OnJuly 9, 2007, the EPA suspended this rule, noting that until further rulemakingoccurs, permitting authorities should continue the existing practice of applyingtheir best professional judgment to minimize impacts on fish and shellfish fromcooling water intake structures. On April 1, 2009, the Supreme Court of theUnited States reversed one significant aspect of the Second Circuit Court'sopinion and decided that Section 316(b) of the Clean Water Act authorizes theEPA to compare costs with benefits in determining the best technology availablefor minimizing adverse environmental impact at cooling water intake structures.FirstEnergy is studying various control options and their costs andeffectiveness. Depending on the results of such studies and the EPA's furtherrulemaking and any action taken by the states exercising best professionaljudgment, the future costs of compliance with these standards may requirematerial capital expenditures. The U.S. Attorney's Office in Cleveland, Ohio has advised FGCO that it isconsidering prosecution under the Clean Water Act and the Migratory Bird TreatyAct for three petroleum spills at the Edgewater, Lakeshore and Bay Shore plantswhich occurred on November 1, 2005, January 26, 2007 and February 27, 2007. FGCOis 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 wasteregulations have been promulgated. Certain fossil-fuel combustion wasteproducts, such as coal ash, were exempted from hazardous waste disposalrequirements pending the EPA's evaluation of the need for future regulation. TheEPA subsequently determined that regulation of coal ash as a hazardous waste isunnecessary. In April 2000, the EPA announced that it will develop nationalstandards regulating disposal of coal ash under its authority to regulatenon-hazardous waste. In February 2009, the EPA requested comments from thestates on options for regulating coal combustion wastes, including regulation asnon-hazardous waste or regulation as a hazardous waste. The future cost ofcompliance with coal combustion waste regulations may be substantial and willdepend, in part, on the regulatory action taken by the EPA and implementation bythe states. Under NRC regulations, FirstEnergy must ensure that adequate funds will beavailable to decommission its nuclear facilities. As of March 31, 2009,FirstEnergy had approximately $1.6 billion invested in external trusts to beused for the decommissioning and environmental remediation of Davis-Besse,Beaver Valley, Perry and TMI-2. As part of the application to the NRC totransfer 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 fundsof approximately 2% over inflation, these trusts are expected to exceed theminimum decommissioning funding requirements set by the NRC. Conservatively,these estimates do not include any return that the trusts may earn over the20-year plant useful life extensions that FirstEnergy (and Exelon for TMI-1 asit relates to the timing of the decommissioning of TMI-2) seeks for thesefacilities. The Utilities have been named as potentially responsible parties at wastedisposal sites, which may require cleanup under the Comprehensive EnvironmentalResponse, Compensation, and Liability Act of 1980. Allegations of disposal ofhazardous substances at historical sites and the liability involved are oftenunsubstantiated and subject to dispute; however, federal law provides that allpotentially responsible parties for a particular site may be liable on a jointand several basis. Environmental liabilities that are considered probable havebeen recognized on the Consolidated Balance Sheet as of March 31, 2009, based onestimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliatedentities to pay. Total liabilities of approximately $91 million (JCP&L - $64million, TE - $1 million, CEI - $1 million and FirstEnergy Corp. - $25 million)have been accrued through March 31, 2009. Included in the total are accruedliabilities of approximately $56 million for environmental remediation of formermanufactured gas plants and gas holder facilities in New Jersey, which are beingrecovered by JCP&L through a non-bypassable SBC. (C) OTHER LEGAL PROCEEDINGS Power Outages and Related Litigation In July 1999, the Mid-Atlantic States experienced a severe heat wave, whichresulted in power outages throughout the service territories of many electricutilities, including JCP&L's territory. In an investigation into the causes ofthe outages and the reliability of the transmission and distribution systems ofall four of New Jersey's electric utilities, the NJBPU concluded that there wasnot 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 andother GPU companies, seeking compensatory and punitive damages arising from theJuly 1999 service interruptions in the JCP&L territory. After various motions, rulings and appeals, the Plaintiffs' claims for consumerfraud, common law fraud, negligent misrepresentation, strict product liability,and punitive damages were dismissed, leaving only the negligence and breach ofcontract 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) theAppellate Division limited the class only to those customers directly impactedby the outages of JCP&L transformers in Red Bank, NJ, based on a common incidentinvolving the failure of the bushings of two large transformers in the Red Banksubstation which resulted in planned and unplanned outages in the area during a2-3 day period, and (2) in March 2007, the Appellate Division remanded thismatter back to the Trial Court to allow plaintiffs sufficient time to establisha damage model or individual proof of damages. Proceedings then continued at thetrial court level and a case management conference with the presiding Judge washeld on June 13, 2008. At that conference, counsel for the Plaintiffs stated hisintent to drop his efforts to create a class-wide damage model and, instead ofdismissing the class action, expressed his desire for a bifurcated trial onliability 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 April20, 2009, the Plaintiffs filed their appeal to the trial court's decision todecertify the class. Nuclear Plant Matters On May 14, 2007, the Office of Enforcement of the NRC issued a Demand forInformation to FENOC, following FENOC's reply to an April 2, 2007 NRC requestfor information about two reports prepared by expert witnesses for an insurancearbitration (the insurance claim was subsequently withdrawn by FirstEnergy inDecember 2007) related to Davis-Besse. The NRC indicated that this informationwas needed for the NRC "to determine whether an Order or other action should betaken pursuant to 10 CFR 2.202, to provide reasonable assurance that FENOC willcontinue to operate its licensed facilities in accordance with the terms of itslicenses and the Commission's regulations." FENOC was directed to submit theinformation to the NRC within 30 days. On June 13, 2007, FENOC filed a responseto the NRC's Demand for Information reaffirming that it accepts fullresponsibility for the mistakes and omissions leading up to the damage to thereactor vessel head and that it remains committed to operating Davis-Besse andFirstEnergy's other nuclear plants safely and responsibly. FENOC submitted asupplemental response clarifying certain aspects of the response to the NRC onJuly 16, 2007. The NRC issued a Confirmatory Order imposing these commitments onFENOC. In an April 23, 2009 Inspection Report, the NRC concluded that FENOC hadcompleted all necessary actions required by the Confirmatory Order. In August 2007, FENOC submitted an application to the NRC to renew the operatinglicenses for the Beaver Valley Power Station (Units 1 and 2) for an additional20 years. The NRC is required by statute to provide an opportunity for membersof 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 ImpactStatement for Beaver Valley. FENOC will continue to work with the NRC Staff asit completes its environmental and technical reviews of the license renewalapplication, and expects to obtain renewed licenses for the Beaver Valley PowerStation in 2009. If renewed licenses are issued by the NRC, the Beaver ValleyPower Station's licenses would be extended until 2036 and 2047 for Units 1 and2, respectively. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) andproceedings related to FirstEnergy's normal business operations pending againstFirstEnergy and its subsidiaries. The other potentially material items nototherwise discussed above are described below. JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002call-out procedure that required bargaining unit employees to respond toemergency power outages. On May 20, 2004, an arbitration panel concluded thatthe call-out procedure violated the parties' collective bargaining agreement. OnSeptember 9, 2005, the arbitration panel issued an opinion to awardapproximately $16 million to the bargaining unit employees. A final orderidentifying the individual damage amounts was issued on October 31, 2007 and theaward appeal process was initiated. The union filed a motion with the federalCourt to confirm the award and JCP&L filed its answer and counterclaim to vacatethe award on December 31, 2007. JCP&L and the union filed briefs in June andJuly of 2008 and oral arguments were held in the fall. On February 25, 2009, thefederal district court denied JCP&L's motion to vacate the arbitration decisionand granted the union's motion to confirm the award. JCP&L filed a Notice ofAppeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment onMarch 6, 2009; the appeal process could take as long as 24 months. JCP&Lrecognized a liability for the potential $16 million award in 2005.Post-judgment interest began to accrue as of February 25, 2009, and theliability will be adjusted accordingly. The union employees at the Bruce Mansfield Plant have been working without alabor contract since February 15, 2008. The parties are continuing to bargainwith the assistance of a federal mediator. FirstEnergy has a strike mitigationplan ready in the event of a strike. The union employees at Met-Ed have been working without a labor contract sinceMay 1, 2009. The parties are continuing to bargain and FirstEnergy has a workcontinuation plan ready in the event of a strike. FirstEnergy accrues legal liabilities only when it concludes that it is probablethat it has an obligation for such costs and can reasonably estimate the amountof such costs. If it were ultimately determined that FirstEnergy or itssubsidiaries have legal liability or are otherwise made subject to liabilitybased on the above matters, it could have a material adverse effect onFirstEnergy's or its subsidiaries' financial condition, results of operations and cash flows. 8. COMMITMENTS, GUARANTEES AND CONTINGENCIES (A) GUARANTEES AND OTHER ASSURANCES As part of normal business activities, FirstEnergy enters into false true Includes disclosure of commitments and contingencies. This element may be used as a single block of text to encapsulate the entire disclosure including data and tables. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name FASB Interpretation (FIN) -Number 14 -Paragraph 3 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 5 -Paragraph 9, 10, 11, 12 false 11 Public Utilities Disclosure [Text Block] 1 us-gaap_PublicUtilitiesDisclosureTextBlock us-gaap true na duration string This element can be used to encapsulate the entire disclosure for public utilities (including data and tables). false false false false false false false false false 1 false false 0 0 9. REGULATORY MATTERS (A) RELIABILITY INITIATIVES In 2005, Congress amended the Federal Power Act to provide forfederally-enforceable mandatory reliability standards. The mandatory reliabilitystandards apply to the bulk power system and impose certain operating, record-keeping and reporting requirements on the Utilities and ATSI. The NERC ischarged with establishing and enforcing these reliability standards, although ithas delegated day-to-day implementation and enforcement of its responsibilitiesto eight regional entities, including ReliabilityFirst Corporation. All ofFirstEnergy's facilities are located within the ReliabilityFirst region.FirstEnergy actively participates in the NERC and ReliabilityFirst stakeholderprocesses, and otherwise monitors and manages its companies in response to theongoing development, implementation and enforcement of the reliability standards. FirstEnergy believes that it is in compliance with all currently-effective andenforceable reliability standards. Nevertheless, it is clear that the NERC,ReliabilityFirst and the FERC will continue to refine existing reliabilitystandards as well as to develop and adopt new reliability standards. Thefinancial impact of complying with new or amended standards cannot be determinedat this time. However, the 2005 amendments to the Federal Power Act provide thatall prudent costs incurred to comply with the new reliability standards berecovered in rates. Still, any future inability on FirstEnergy's part to complywith the reliability standards for its bulk power system could result in theimposition of financial penalties and thus have a material adverse effect on itsfinancial condition, results of operations and cash flows. In April 2007, ReliabilityFirst performed a routine compliance audit ofFirstEnergy's bulk-power system within the MISO region and found it to be infull compliance with all audited reliability standards. Similarly, in October2008, ReliabilityFirst performed a routine compliance audit of FirstEnergy'sbulk-power system within the PJM region and found it to be in full compliancewith 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 theaffected area losing power. Power was restored to most customers within a fewhours and to all customers within eleven hours. On December 16, 2008, JCP&Lprovided preliminary information about the event to certain regulatory agencies,including the NERC. On March 31, 2009, the NERC initiated a Compliance ViolationInvestigation in order to determine JCP&L's contribution to the electrical eventand to review any potential violation of NERC Reliability Standards associatedwith the event. The initial phase of the investigation requires JCP&L to respondto NERC's request for factual data about the outage. JCP&L submitted its writtenresponse 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 datarequest. (B ) OHIO On June 7, 2007, the Ohio Companies filed an application for an increase inelectric distribution rates with the PUCO and, on August 6, 2007, updated theirfiling to support a distribution rate increase of $332 million. On December 4,2007, the PUCO Staff issued its Staff Reports containing the results of itsinvestigation into the distribution rate request. On January 21, 2009, the PUCOgranted the Ohio Companies' application to increase electric distribution ratesby $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5million). 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 ofthis 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 utilitiesto file an ESP, and permitted the filing of an MRO. On July 31, 2008, the OhioCompanies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCOdenied the MRO application; however, the PUCO later granted the Ohio Companies'application for rehearing for the purpose of further consideration of thematter. The ESP proposed to phase in new generation rates for customersbeginning 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 raterequest described above. In response to the PUCO's December 19, 2008 order,which significantly modified and approved the ESP as modified, the OhioCompanies notified the PUCO that they were withdrawing and terminating the ESPapplication in addition to continuing their current rate plan in effect asallowed by the terms of SB221. On December 31, 2008, the Ohio Companiesconducted a CBP for the procurement of electric generation for retail customersfrom January 5, 2009 through March 31, 2009. The average winning bid price wasequivalent to a retail rate of 6.98 cents per kwh. The power supply obtainedthrough this process provides generation service to the Ohio Companies' retailcustomers who choose not to shop with alternative suppliers. On January 9, 2009,the Ohio Companies requested the implementation of a new fuel rider to recoverthe costs resulting from the December 31, 2008 CBP. The PUCO ultimately approvedthe Ohio Companies' request for a new fuel rider to recover increased costsresulting from the CBP but did not authorize OE and TE to continue collectingRTC or allow the Ohio Companies to continue collections pursuant to the twoexisting fuel riders. The new fuel rider allows for current recovery of theincreased purchased power costs for OE and TE, and authorizes CEI to collect aportion of those costs currently and defer the remainder for future recovery. On January 29, 2009, the PUCO ordered its Staff to develop a proposal toestablish an ESP for the Ohio Companies. On February 19, 2009, the OhioCompanies filed an Amended ESP application, including an attached Stipulationand Recommendation that was signed by the Ohio Companies, the Staff of the PUCO,and many of the intervening parties. Specifically, the Amended ESP provides thatgeneration will be provided by FES at the average wholesale rate of the CBPprocess described above for April and May 2009 to the Ohio Companies for theirnon-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 clockCBP on a slice-of-system basis. The PUCO may, at its discretion, phase-in aportion of any increase resulting from this CBP process by authorizing deferralof related purchased power costs, subject to specified limits. The Amended ESPfurther provides that the Ohio Companies will not seek a base distribution rateincrease, subject to certain exceptions, with an effective date of such increasebefore January 1, 2012, that CEI will agree to write-off approximately $216million of its Extended RTC balance, and that the Ohio Companies will collect adelivery service improvement rider at an overall average rate of $.002 per kWhfor the period of April 1, 2009 through December 31, 2011. The Amended ESP alsoaddresses a number of other issues, including but not limited to, rate designfor various customer classes, resolution of the prudence review and thecollection of deferred costs that were approved in prior proceedings. OnFebruary 26, 2009, the Ohio Companies filed a Supplemental Stipulation, whichwas signed or not opposed by virtually all of the parties to the proceeding,that supplemented and modified certain provisions of the February 19 Stipulationand Recommendation. Specifically, the Supplemental Stipulation modified theprovision relating to governmental aggregation and the Generation ServiceUncollectible Rider, provided further detail on the allocation of the economicdevelopment funding contained in the Stipulation and Recommendation, andproposed additional provisions related to the collaborative process for thedevelopment of energy efficiency programs, among other provisions. The PUCOadopted and approved certain aspects of the Stipulation and Recommendation onMarch 4, 2009, and adopted and approved the remainder of the Stipulation andRecommendation and Supplemental Stipulation without modification on March 25,2009. Certain aspects of the Stipulation and Recommendation and SupplementalStipulation take effect on April 1, 2009 while the remaining provisions takeeffect on June 1, 2009. The CBP auction is currently scheduled to begin on May13, 2009. The bidding will occur for a single, two-year product and there willnot be a load cap for the bidders. FES may participate without limitation. SB221 also requires electric distribution utilities to implement energyefficiency programs that achieve an energy savings equivalent of approximately166,000 MWH in 2009, 290,000 MWH in 2010, 410,000 MWH in 2011, 470,000 MWH in2012 and 530,000 MWH in 2013. Utilities are also required to reduce peak demandin 2009 by one percent, with an additional seventy-five hundredths of onepercent reduction each year thereafter through 2018. Costs associated withcompliance are recoverable from customers. (C) PENNSYLVANIA Met-Ed and Penelec purchase a portion of their PLR and default servicerequirements from FES through a fixed-price partial requirements wholesale powersales agreement. The agreement allows Met-Ed and Penelec to sell the output ofNUG energy to the market and requires FES to provide energy at fixed prices toreplace any NUG energy sold to the extent needed for Met-Ed and Penelec tosatisfy their PLR and default service obligations. If Met-Ed and Penelec were toreplace the entire FES supply at current market power prices withoutcorresponding regulatory authorization to increase their generation prices tocustomers, each company would likely incur a significant increase in operatingexpenses and experience a material deterioration in credit quality metrics.Under such a scenario, each company's credit profile would no longer be expectedto support an investment grade rating for their fixed income securities. If FESultimately determines to terminate, reduce, or significantly modify theagreement prior to the expiration of Met-Ed's and Penelec's generation rate capsin 2010, timely regulatory relief is not likely to be granted by the PPUC. SeeFERC Matters below for a description of the Third Restated Partial RequirementsAgreement, executed by the parties on October 31, 2008, that limits the amountof energy and capacity FES must supply to Met-Ed and Penelec. In the event of athird party supplier default, the increased costs to Met-Ed and Penelec could bematerial. On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to theTSC rider for the period June 1, 2008, through May 31, 2009. Various intervenorsfiled complaints against those filings. In addition, the PPUC ordered aninvestigation to review the reasonableness of Met-Ed's TSC, while at the sametime allowing Met-Ed to implement the rider June 1, 2008, subject to refund. OnJuly 15, 2008, the PPUC directed the ALJ to consolidate the complaints againstMet-Ed with its investigation and a litigation schedule was adopted. Hearingsand briefing for both Met-Ed and Penelec have concluded and the companies areawaiting a Recommended Decision from the ALJ. The TSCs include a component fromunder-recovery of actual transmission costs incurred during the prior period(Met-Ed - $144 million and Penelec - $4 million) and future transmission costprojections for June 2008 through May 2009 (Met-Ed - $258 million and Penelec -$92 million). Met-Ed received PPUC approval for a transition approach that wouldrecover past under-recovered costs plus carrying charges through the new TSCover 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 theperiod June 1, 2009 through May 31, 2010, as required in connection with thePPUC's January 2007 rate order. For Penelec's customers, the new TSC wouldresult in an approximate 1% decrease in monthly bills, reflecting projected PJMtransmission costs as well as a reconciliation for costs already incurred. TheTSC for Met-Ed's customers would increase to recover the additional PJM chargespaid by Met-Ed in the previous year and to reflect updated projected costs. Inorder to gradually transition customers to the higher rate, Met-Ed is proposingto continue to recover the prior period deferrals allowed in the PPUC's May 2008Order and defer $57.5 million of projected costs into a future TSC to be fullyrecovered by December 31, 2010. Under this proposal, monthly bills for Met-Ed'scustomers would increase approximately 9.4% for the period June 2009 through May2010. On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 intolaw which became effective on November 14, 2008 as Act 129 of 2008. The billaddresses issues such as: energy efficiency and peak load reduction; generationprocurement; time-of-use rates; smart meters and alternative energy. Act 129requires utilities to file with the PPUC an energy efficiency and peak loadreduction plan by July 1, 2009 and a smart meter procurement and installationplan by August 14, 2009. On January 15, 2009, in compliance with Act 129, thePPUC issued its proposed guidelines for the filing of utilities' energyefficiency and peak load reduction plans. Similar guidelines related to SmartMeter 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 willbe procured through a competitive procurement process that must include a mix oflong-term and short-term contracts and spot market purchases; - the competitive procurement process must be approved by the PPUC and mayinclude auctions, RFPs, and/or bilateral agreements; - utilities must provide for the installation of smart meter technologywithin 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 andMay 31, 2013, respectively; and - an expanded definition of alternative energy to include additional typesof hydroelectric and biomass facilities. Legislation addressing rate mitigation and the expiration of rate caps was notenacted in 2008; however, several bills addressing these issues have beenintroduced in the current legislative session, which began in January 2009. Thefinal form and impact of such legislation is uncertain. On February 26, 2009, the PPUC approved a Voluntary Prepayment Pan requested byMet-Ed and Penelec that provides an opportunity for residential and smallcommercial customers to prepay an amount on their monthly electric bills during2009 and 2010. Customer prepayments earn interest at 7.5% and will be used toreduce electricity charges in 2011 and 2012. On February 20, 2009, Met-Ed and Penelec filed with the PPUC a generationprocurement plan covering the period January 1, 2011 through May 31, 2013. Thecompanies' plan is designed to provide adequate and reliable service via aprudent mix of long-term, short-term and spot market generation supply, asrequired by Act 129. The plan proposes a staggered procurement schedule, whichvaries by customer class, through the use of a descending clock auction. Met-Edand Penelec have requested PPUC approval of their plan by November 2009. On March 31, 2009, Met-Ed and Penelec submitted their 5-year NUG StatementCompliance Filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential classwith 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 acorresponding increase in the generation rate and the shopping credit. Whilethese changes would result in additional annual generation revenue (Met-Ed - $27million and Penelec - $51 million), overall rates would remain unchanged. ThePPUC must act on this filing within 120 days. (D) NEW JERSEY JCP&L is permitted to defer for future collection from customers the amounts bywhich its costs of supplying BGS to non-shopping customers, costs incurred underNUG agreements, and certain other stranded costs, exceed amounts collectedthrough BGS and NUGC rates and market sales of NUG energy and capacity. As ofMarch 31, 2009, the accumulated deferred cost balance totaled approximately $165million. In accordance with an April 28, 2004 NJBPU order, JCP&L filed testimony on June7, 2004, supporting continuation of the current level and duration of thefunding of TMI-2 decommissioning costs by New Jersey customers without areduction, termination or capping of the funding. On September 30, 2004, JCP&Lfiled an updated TMI-2 decommissioning study. This study resulted in an updatedtotal decommissioning cost estimate of $729 million (in 2003 dollars) comparedto the estimated $528 million (in 2003 dollars) from the prior 1995decommissioning study. The DPA filed comments on February 28, 2005 requestingthat decommissioning funding be suspended. On March 18, 2005, JCP&L filed aresponse to those comments. JCP&L responded to additional NJBPU staff discoveryrequests in May and November 2007 and also submitted comments in the proceedingin 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 thatincludes a request for a reduction in the level of recovery of TMI-2decommissioning costs based on an updated TMI-2 decommissioning cost analysisdated January 2009. This matter is currently pending before the NJBPU. On August 1, 2005, the NJBPU established a proceeding to determine whetheradditional ratepayer protections are required at the state level in light of therepeal of the PUHCA pursuant to the EPACT. The NJBPU approved regulationseffective October 2, 2006 that prevent a holding company that owns a gas orelectric public utility from investing more than 25% of the combined assets ofits utility and utility-related subsidiaries into businesses unrelated to theutility industry. These regulations are not expected to materially impactFirstEnergy or JCP&L. Also, in the same proceeding, the NJBPU Staff issued anadditional draft proposal on March 31, 2006 addressing various issues includingaccess to books and records, ring-fencing, cross subsidization, corporategovernance and related matters. Following public hearing and consideration ofcomments from interested parties, the NJBPU approved final regulations effectiveApril 6, 2009. These regulations are not expected to materially impactFirstEnergy or JCP&L. New Jersey statutes require that the state periodically undertake a planningprocess, known as the EMP, to address energy related issues including energysecurity, economic growth, and environmental impact. The EMP is to be developedwith involvement of the Governor's Office and the Governor's Office of EconomicGrowth, and is to be prepared by a Master Plan Committee, which is chaired bythe 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 energyconsumption 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 andother generation resources consistent with the state's greenhouse gas targets;and - invest in innovative clean energy technologies and businesses to stimulatethe industry's growth in New Jersey. On January 28, 2009, the NJBPU adopted an order establishing the general processand contents of specific EMP plans that must be filed by December 31, 2009 byNew 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 haveon 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 infrastructureand energy efficiency projects in 2009. An estimated $40 million will be spenton infrastructure projects, including substation upgrades, new transformers,distribution line re-closers and automated breaker operations. Approximately $34million will be spent implementing new demand response programs as well asexpanding on existing programs. Another $11 million will be spent on energyefficiency, specifically replacing transformers and capacitor control systemsand installing new LED street lights. The remaining $13 million will be spent onenergy efficiency programs that will complement those currently being offered.Completion of the projects is dependent upon resolution of regulatory issuesincluding 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 outrate for transmission service between the MISO and PJM regions. The FERC'sintent was to eliminate multiple transmission charges for a single transactionbetween the MISO and PJM regions. The FERC also ordered MISO, PJM and thetransmission owners within MISO and PJM to submit compliance filings containinga rate mechanism to recover lost transmission revenues created by elimination ofthis charge (referred to as the Seams Elimination Cost Adjustment or SECA)during a 16-month transition period. The FERC issued orders in 2005 setting theSECA for hearing. The presiding judge issued an initial decision on August 10,2006, rejecting the compliance filings made by MISO, PJM, and the transmissionowners, and directing new compliance filings. This decision is subject to reviewand approval by the FERC. Briefs addressing the initial decision were filed onSeptember 11, 2006 and October 20, 2006. A final order is pending before theFERC, and in the meantime, FirstEnergy affiliates have been negotiating andentering into settlement agreements with other parties in the docket to mitigatethe risk of lower transmission revenue collection associated with an adverseorder. On September 26, 2008, the MISO and PJM transmission owners filed amotion requesting that the FERC approve the pending settlements and act on theinitial decision. On November 20, 2008, FERC issued an order approvinguncontested settlements, but did not rule on the initial decision. On December19, 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 FERCpursuant 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 thefilings. In the first filing, the settling transmission owners submitted afiling justifying continuation of their existing rate design within the PJM RTO.Hearings were held and numerous parties appeared and litigated various issuesconcerning PJM rate design; notably AEP, which proposed to create a "postagestamp", or average rate for all high voltage transmission facilities across PJMand a zonal transmission rate for facilities below 345 kV. This proposal wouldhave the effect of shifting recovery of the costs of high voltage transmissionlines to other transmission zones, including those where JCP&L, Met-Ed, andPenelec serve load. On April 19, 2007, the FERC issued an order finding that thePJM transmission owners' existing "license plate" or zonal rate design was justand reasonable and ordered that the current license plate rates for existingtransmission facilities be retained. On the issue of rates for new transmissionfacilities, the FERC directed that costs for new transmission facilities thatare rated at 500 kV or higher are to be collected from all transmission zonesthroughout the PJM footprint by means of a postage-stamp rate. Costs for newtransmission facilities that are rated at less than 500 kV, however, are to beallocated on a "beneficiary pays" basis. The FERC found that PJM's currentbeneficiary-pays cost allocation methodology is not sufficiently detailed and,in a related order that also was issued on April 19, 2007, directed thathearings be held for the purpose of establishing a just and reasonable costallocation 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. OnFebruary 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 IllinoisCommerce Commission, the PUCO and Dayton Power & Light have also appealed theseorders to the Seventh Circuit Court of Appeals. The appeals of these parties andothers have been consolidated for argument in the Seventh Circuit. Oral argumentwas 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 ofthe revenue requirement of existing transmission facilities of other utilitiesto JCP&L, Met-Ed and Penelec. In addition, the FERC's decision to allocate thecost of new 500 kV and above transmission facilities on a PJM-wide basis willreduce the costs of future transmission to be recovered from the JCP&L, Met-Edand Penelec zones. A partial settlement agreement addressing the "beneficiarypays" methodology for below 500 kV facilities, but excluding the issue ofallocating new facilities costs to merchant transmission entities, was filed onSeptember 14, 2007. The agreement was supported by the FERC's Trial Staff, andwas certified by the Presiding Judge to the FERC. On July 29, 2008, the FERCissued an order conditionally approving the settlement subject to the submissionof 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 incorporatecost responsibility assignments for below 500 kV upgrades included in PJM'sRegional Transmission Expansion Planning process in accordance with thesettlement. The FERC conditionally accepted the compliance filing on January28, 2009. PJM submitted a further compliance filing on March 2, 2009, which wasaccepted by the FERC on April 10, 2009. The remaining merchant transmission costallocation issues were the subject of a hearing at the FERC in May 2008. Aninitial decision was issued by the Presiding Judge on September 18, 2008. PJMand FERC trial staff each filed a Brief on Exceptions to the initial decision onOctober 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 makefilings on or before August 1, 2007 to reevaluate transmission rate designwithin MISO, and between MISO and PJM. On August 1, 2007, filings were made byMISO, PJM, and the vast majority of transmission owners, including FirstEnergyaffiliates, which proposed to retain the existing transmission rate design.These filings were approved by the FERC on January 31, 2008. As a result of theFERC's approval, the rates charged to FirstEnergy's load-serving affiliates fortransmission service over existing transmission facilities in MISO and PJM areunchanged. In a related filing, MISO and MISO transmission owners requested thatthe current MISO pricing for new transmission facilities that spreads 20% of thecost of new 345 kV and higher transmission facilities across the entire MISOfootprint (known as the RECB methodology) be retained. On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of theFederal Power Act seeking to have the entire transmission rate design and costallocation methods used by MISO and PJM declared unjust, unreasonable, andunduly discriminatory, and to have the FERC fix a uniform regional transmissionrate design and cost allocation method for the entire MISO and PJM "SuperRegion" that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmissioncustomers. Lower voltage facilities would continue to be recovered in the localutility transmission rate zone through a license plate rate. AEP requested arefund effective October 1, 2007, or alternatively, February 1, 2008. On January31, 2008, the FERC issued an order denying the complaint. The effect of thisorder is to prevent the shift of significant costs to the FirstEnergy zones inMISO 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, andDecember 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 tointervene on March 10, 2009. Duquesne's Request to Withdraw from PJM On November 8, 2007, Duquesne Light Company (Duquesne) filed a request with theFERC to exit PJM and to join MISO. Duquesne's proposed move would affectnumerous FirstEnergy interests, including but not limited to the terms underwhich FirstEnergy's Beaver Valley Plant would continue to participate in PJM'senergy markets. FirstEnergy, therefore, intervened and participated fully in allof the FERC dockets that were related to Duquesne's proposed move. In November, 2008, Duquesne and other parties, including FirstEnergy, negotiateda settlement that would, among other things, allow for Duquesne to remain in PJMand provide for a methodology for Duquesne to meet the PJM capacity obligationsfor the 2011-2012 auction that excluded the Duquesne load. The settlementagreement was filed on December 10, 2008 and approved by the FERC in an orderissued on January 29, 2009. MISO opposed the settlement agreement pendingresolution of exit fees alleged to be owed by Duquesne. The FERC did not resolvethe exit fee issue in its order. On March 2, 2009, the PPUC filed for rehearingof the FERC's January 29, 2009 order approving the settlement. Thereafter,FirstEnergy and other parties filed in opposition to the rehearing request. ThePPUC's rehearing request, and the pleadings in opposition thereto, are pendingbefore 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 RPMBuyers) filed a complaint at the FERC against PJM alleging that three of thefour transitional RPM auctions yielded prices that are unjust and unreasonableunder the Federal Power Act. On September 19, 2008, the FERC denied the RPMBuyers' complaint. However, the FERC did grant the RPM Buyers' request for atechnical conference to review aspects of the RPM. The FERC also ordered PJM tofile on or before December 15, 2008, a report on potential adjustments to theRPM program as suggested in a Brattle Group report. On December 12, 2008, PJMfiled proposed tariff amendments that would adjust slightly the RPM program. PJMalso requested that the FERC conduct a settlement hearing to address changes tothe RPM and suggested that the FERC should rule on the tariff amendments only ifsettlement could not be reached in January, 2009. The request for settlementhearings was granted. Settlement had not been reached by January 9, 2009 and,accordingly, FirstEnergy and other parties submitted comments on PJM's proposedtariff amendments. On January 15, 2009, the Chief Judge issued an orderterminating settlement talks. On February 9, 2009, PJM and a group ofstakeholders 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, tariffprovisions submitted by PJM, revising certain parts of its RPM. Ordered changesincluded making incremental improvements to RPM; however, the basic construct ofRPM remains intact. On April 3, 2009, PJM filed with the FERC requestingclarification 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 theMarch 26, 2009 Order; numerous parties have filed requests for rehearing of theMarch 26, 2009 Order. In addition, the FERC has indefinitely postponed thetechnical 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 enforceableplanning reserve requirement in the MISO tariff for load-serving entities suchas the Ohio Companies, Penn Power, and FES. This requirement is proposed tobecome effective for the planning year beginning June 1, 2009. The filing wouldpermit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless thestate utility regulatory agency establishes a different planning reserve forload-serving entities in its state. FirstEnergy believes the proposal promotes amechanism that will result in commitments from both load-serving entities andresources, including both generation and demand side resources that arenecessary for reliable resource adequacy and planning in the MISO footprint.Comments on the filing were submitted on January 28, 2008. The FERCconditionally approved MISO's Resource Adequacy proposal on March 26, 2008,requiring MISO to submit to further compliance filings. Rehearing requests arepending on the FERC's March 26 Order. On May 27, 2008, MISO submitted acompliance filing to address issues associated with planning reserve margins. OnJune 17, 2008, various parties submitted comments and protests to MISO'scompliance filing. FirstEnergy submitted comments identifying specific issuesthat must be clarified and addressed. On June 25, 2008, MISO submitted a secondcompliance filing establishing the enforcement mechanism for the reserve marginrequirement which establishes deficiency payments for load-serving entities thatdo not meet the resource adequacy requirements. Numerous parties, includingFirstEnergy, protested this filing. On October 20, 2008, the FERC issued three orders essentially permitting theMISO Resource Adequacy program to proceed with some modifications. First, theFERC accepted MISO's financial settlement approach for enforcement of ResourceAdequacy subject to a compliance filing modifying the cost of new entry penalty.Second, the FERC conditionally accepted MISO's compliance filing on thequalifications for purchased power agreements to be capacity resources, loadforecasting, loss of load expectation, and planning reserve zones. Additionalcompliance filings were directed on accreditation of load modifying resourcesand price responsive demand. Finally, the FERC largely denied rehearing of itsMarch 26 order with the exception of issues related to behind the meterresources and certain ministerial matters. On November 19, 2008, MISO madevarious compliance filings pursuant to these orders. Issuance of orders onrehearing and two of the compliance filings occurred on February 19, 2009. Nomaterial changes were made to MISO's Resource Adequacy program. On April 16,2009, the FERC issued an additional order on rehearing and compliance, approvingMISO's proposed financial settlement provision for Resource Adequacy. The MISOResource 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 itsgeneration-controlling subsidiaries, filed an application with the FERC seekinga 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 continuesupplying a material portion of the electric load requirements of the OhioCompanies after January 1, 2009 pursuant to either an ESP or MRO as filed withthe PUCO. FES previously obtained a similar waiver for electricity sales to itsaffiliates in New Jersey, New York, and Pennsylvania. On December 23, 2008, theFERC issued an order granting the waiver request and the Ohio Companies made therequired compliance filing on December 30, 2008. In January 2009, severalparties 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 requestsand responses are pending before the FERC. FES supplied all of the power requirements for the Ohio Companies pursuant to aPower Supply Agreement that ended on December 31, 2008. On January 2, 2009, FESsigned an agreement to provide 75% of the Ohio Companies' power requirements forthe period January 5, 2009 through March 31, 2009. Subsequently, FES signed anagreement to provide 100% of the Ohio Companies' power requirements for theperiod April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued anorder approving these two affiliate sales agreements. FERC authorization forthese 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. TheThird Restated Partial Requirements Agreement limits the amount of capacity andenergy required to be supplied by FES in 2009 and 2010 to roughly two-thirds ofthese affiliates' power supply requirements. Met-Ed, Penelec, and Waverly havecommitted resources in place for the balance of their expected power supplyduring 2009 and 2010. Under the Third Restated Partial Requirements Agreement,Met-Ed, Penelec, and Waverly are responsible for obtaining additional powersupply requirements created by the default or failure of supply of theircommitted resources. Prices for the power provided by FES were not changed inthe Third Restated Partial Requirements Agreement. 9. REGULATORY MATTERS (A) RELIABILITY INITIATIVES In 2005, Congress amended the Federal Power Act to provide forfederally-enforceable mandatory false true This element can be used to encapsulate the entire disclosure for public utilities (including data and tables). Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 71 false 12 Schedule of New Accounting Pronouncements and Changes in Accounting Principles [Text Block] 1 us-gaap_ScheduleOfNewAccountingPronouncementsAndChangesInAccountingPrinciplesTextBlock us-gaap true na duration string Represents disclosure of any changes in an accounting principle, including a change from one generally accepted accounting... false false false false false false false false false 1 false false 0 0 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 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. FirstEnergy will expand its disclosures related to postretirement benefit plan assets as a result of this FSP. 10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS FSP FAS 157-4 - "Determining Fair Value When the Volume and Level of Activity for the Asset or false true Represents disclosure of any changes in an accounting principle, including a change from one generally accepted accounting principle to another generally accepted accounting principle when there are two or more generally accepted accounting principles that apply or when the accounting principle formerly used is no longer generally accepted. Also disclose any change in the method of applying an accounting principle, or any change in an accounting principle required by a new pronouncement in the unusual instance that a new pronouncement does not include specific transition provisions. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 154 -Paragraph 2, 17, 18 Reference 2: http://www.xbrl.org/2003/role/presentationRef -Publisher AICPA -Name Accounting Principles Board Opinion (APB) -Number 28 -Paragraph 23, 24 Reference 3: http://www.xbrl.org/2003/role/presentationRef -Publisher SEC -Name Regulation S-X (SX) -Number 210 -Section 01 -Paragraph b -Subparagraph 6 -Article 10 false 13 Segment Reporting Disclosure [Text Block] 1 us-gaap_SegmentReportingDisclosureTextBlock us-gaap true na duration string This element may be used to capture the complete disclosure of reporting segments including data and tables. Reportable... false false false false false false false false false 1 false false 0 0 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." 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 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 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 the 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 MISO to deliver electricity to the segment's customers. The segment's internal revenues represent 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 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 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) 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. 11. SEGMENT INFORMATION FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio false true This element may be used to capture the complete disclosure of reporting segments including data and tables. Reportable segments include those that that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10% or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments. Reference 1: http://www.xbrl.org/2003/role/presentationRef -Publisher FASB -Name Statement of Financial Accounting Standard (FAS) -Number 131 false false 1 12 true UnKnown UnKnown UnKnown false true